June 11, 2010

Environmental Protection Agency

EPA Docket Center (EPA/DC)

Attention Docket EPA–HQ–OAR–2009– 0923 

Mail Code 2822T

1200 Pennsylvania Avenue, NW

Washington, DC 20460.

Re: Comments from El Paso Corporation on the Proposed Rule for

Mandatory Reporting of Greenhouse Gases: Petroleum and Natural Gas Systems,

Federal Register / Vol. 75, No. 69 / Monday, April 12, 2010 

Docket ID No. EPA–HQ–OAR–2009–0923

Dear Sir or Madam:

El Paso Corporation (El Paso) respectfully submits the attached comments on the proposed 

Mandatory Reporting of Greenhouse Gases: Petroleum and Natural Gas Systems published 

in the Federal Register1 on April 12, 2010 (proposed rule). El Paso Corporation (NYSE: EP) 

provides natural gas and related energy products in a safe, efficient, and dependable manner. We 

are organized around two core businesses — pipelines and exploration and production (E&P). 

We own North America’s largest natural gas pipeline system, transporting approximately one 

quarter of the natural gas consumed in the U.S. each day. Our exploration and production 

company ranks among the top 10 domestic independent natural gas producers operating in key 

onshore and offshore basins. We operate 198 compressor stations, 11 processing plants (per 

proposed definition in the Subpart W rule), 11 underground storage facilities, 40 offshore 

production facilities, 62 onshore production reporting fields, and one Liquefied Natural Gas 

(LNG) import terminal. Of these, 156 facilities could be subject to the proposed rule. Our 

detailed comments related to the proposed rule are included in Attachment 2.

As an industry leader, El Paso has been actively participating in regional and national policy 

discussions and has instituted internal guiding principles on the issue of addressing climate 

change2

. We have received approval from the Federal Energy Regulatory Commission (FERC) 

to construct a multi-billion dollar pipeline from Wyoming to the California/Oregon border, 

known as the Ruby pipeline and it is our goal to make the Ruby pipeline a carbon-neutral project. 

We are members of the California Climate Action Registry (CCAR), and have the honor of being 

the first natural gas company to certify its total GHG emissions from US operations. Our 

pipeline subsidiaries, El Paso Natural Gas (EPNG) and Colorado Interstate Gas (CIG) are 

“founding reporters” of “The Climate Registry” (TCR). Being an industry leader, we understand 

 1 Federal Register / Vol. 75, No. 69 /April 12, 2010 2 http://elpaso.com/CSR/neighbortohave.html
the regulatory, technical and commercial complexities associated with accounting and reporting 

of GHG emissions related to our sector. We have participated in and communicated our 

experiences and recommendations under both the AB 323 and Western Climate Initiative (WCI) 

rule development4. A summary of our leadership credentials is provided in Attachment 3.

El Paso has been participating in the EPA Natural Gas Star program since 1993 and has been 

recognized as the “Partner of the Year” multiple times. Through the Natural Gas Star program 

and internal voluntary monitoring initiatives El Paso gained superior technical knowledge on the 

capabilities and limitations related to fugitive emission monitoring and reductions in the natural 

gas sector. 

Our commitment related to environmental issues carries out our core value of Stewardship as we 

always strive to be good stewards of the environment and within our communities. We are the 

only natural gas company with practical experience in conducting total US GHG inventories 

from our E&P, natural gas pipeline and processing operations under a stringent reporting 

protocol like the CCAR reporting protocol. Add the Natural Gas Star experience and associated 

monitoring leadership, and our experience related to reporting and monitoring in the gas 

transmission, processing and E&P sectors is unrivalled in the world.

We offer these comments for your consideration and look forward to working with you on 

making the reporting program a success. We also endorse comments filed by the Interstate 

Natural Gas Association of America (INGAA), except where noted. We hope you find these 

comments constructive as you deliberate the contours and content of a first of its kind, economywide GHG reporting program. Please feel free to contact me at (713) 420-7913 or 

fiji.george@elpaso.com, with questions or for further information or clarification. 

Sincerely, 

Fiji George 

Carbon Strategies Director

El Paso Corporation

 3Multiple comments filed with WCI, California Public Utility Commission, California Energy Commission and California 

Air Resources Board. 4 Specific comments on Mandatory Reporting filed with WCI on August 11, 2008 and October 14, 2008. Additional 

 reported design-related comments were filed in relation with designing the WCI program.
ATTACHMENTS

Attachment 1: Summary of El Paso’s Comments on the Proposed Rule for Mandatory 

Reporting of Greenhouse Gases

Attachment 2: El Paso’s Detailed Comments on the Proposed Rule for Mandatory 

Reporting of Greenhouse Gases

Attachment 3: El Paso’s GHG Leadership Credentials

APPENDICES

Appendix I: Support Documentation for “As Found” Monitoring Proposal 

Appendix II: Analysis of the EPA Proposed Greenhouse Gas Mandatory Reporting 

Rule Cost Impacts for Natural Gas Systems

Appendix III: Legal Authority and Linkage to CAA Regulations

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ATTACHMENT 1

SUMMARY OF EL PASO’S COMMENTS ON THE PROPOSED RULE FOR 

MANDATORY REPORTING OF GREENHOUSE GASES

El Paso’s comments are summarized below. We endorse comments filed by the Interstate 

Natural Gas Association of America (INGAA), except where noted. Additional details in 

support of these comments are provided in Attachment 2.

I. Preamble Section II.(A.) on page 18612.—(KEY ISSUE) El Paso requests the EPA 

establish a June 30 submittal deadline for all emission reports related to Subpart W.

II. Preamble Section II.(C.) on page 18613.—El Paso requests the EPA to consider utilizing 

the term “reporting area” under the definition of the source category for Onshore Petroleum 

and Natural Gas Production. 

III. Preamble at 18618 and 18625.—(KEY ISSUE) El Paso believes that EPA has significantly 

underestimated the level of effort and cost implications for Subpart W, as it applies to 

onshore oil and gas production operations. As a result, reporting should be based on a field 

basis. A detailed cost analysis has been included in Appendix II. 

IV. Proposed Rule § 98.231 Applicability Analysis.—(KEY ISSUE) EPA must provide 

flexibility to regulated facilities with respect to initial year applicability analysis. El Paso 

requests the EPA consider two screening methods to assist with the initial year applicability 

determination. This proposal differs from the INGAA proposal. In addition, El Paso requests 

that EPA promulgate a safe harbor provision for the first year of reporting. EPA can draw 

from prior regulatory precedent granted by the Federal Energy Regulatory Commission 

(FERC). The FERC granted a one-year safe harbor provision when it issued Order No. 704, 

which requires the reporting of natural gas transactions (FERC Form No. 552). This 

provision gave the regulated community the benefit of a rebuttable presumption that the data 

provided was accurate and submitted in good faith and provided assurance that the regulatory 

agency (the FERC) would not impose penalties for errors in reporting. 

V. Proposed Rule § 98.232 GHGs to report.—(KEY ISSUE) El Paso requests the EPA to 

consider practical concerns in complying with a March 31, 2012 initial deadline and adopt a 

“transitional” program to phase in affected Subpart W facilities into full reporting per EPA 

final methods by 2015. 

VI. Proposed Rule § 98.232(b) GHGs to report for Offshore Petroleum and Natural Gas 

Production.—Onshore petroleum and natural gas production operators should be allowed to 

use the same approach as the offshore petroleum and natural gas production operators due to 

similar emission sources, functional use and production practices.
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VII. Proposed Rule § 98.233 Calculating GHG emissions.—El Paso encourages the EPA to 

allow annual emissions to be optionally based on all direct measurement results that may be 

available during a calendar year for any emission source. 

VIII. Proposed Rule § 98.233(a) Natural gas pneumatic high bleed device venting.—El Paso 

encourages the EPA to provide a default leak rate for those devices where manufacturer and 

model is not known. 

IX. Proposed Rule § 98.233(d) Acid gas removal (AGR) vent stacks.—El Paso encourages the 

EPA to allow reporters to estimate the inlet and outlet volumes if not currently metered. 

X. Proposed Rule § 98.233(e) Dehydrator vent stacks.—El Paso requests confirmation that 

engineering estimates are acceptable as the operational parameters used to run the GlyCalc 

model. In addition, El Paso requests that dehydrator units with a throughput of less than ten 

(10) MMscf per day be exempted from the rule. 

XI. Proposed Rule § 98.233(g) Gas well venting during unconventional well completions 

and workovers.—As in several other recommendations related to providing reporters 

monitoring flexibility, El Paso requests the third method from the Technical Support 

Document be included as an alternative method in the rule, since the approach uses 

information commonly tracked from completion and workover activities. 

XII. Proposed Rule § 98.233(i) Blowdown vent stacks.—El Paso requests that an alternate

method be added to allow blowdown volumes be corrected to standard conditions for each 

event prior to aggregation.

XIII. Proposed Rule § 98.233(j) Onshore production & processing storage tanks. —El Paso 

requests confirmation that engineering estimates can be used for the operational parameters 

to run the E&P Tanks model. In addition, El Paso requests that tanks with a throughput of 

less than five (5) barrels per day be exempted from the rule. 

XIV. Proposed Rule § 98.233(o) Centrifugal compressor wet seal degassing vents.—El Paso 

requests clarification on the operating mode requirements for surveys of centrifugal wet seal 

vents. It is our interpretation that Section 98.233(o) does not currently prescribe that wet seal 

vents be surveyed in each of the operational modes that occur during a reporting period. 

XV. Proposed Rule § 98.233(p) Reciprocating compressor rod packing venting.—(KEY 

ISSUE) El Paso requests the EPA to allow surveys of compressors to take place in an “as 

found” mode. While our overall principle recommendation is the same as INGAA’s, we 

have provided options and justified our recommendations based on actual field experience at 

El Paso sites and review of existing literature on this subject.

XVI. Proposed Rule § 98.233(q) Leak detection and leaker emission factors.—El Paso requests 

monitoring flexibility and urges the use of a facility emission factor to be used as an 

alternative to Infra-red (IR) camera leak detection/leaker emission factors for standard 

components at transmission compression and underground storage facilities. 
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XVII. Proposed Rule § 98.233(q)(2) Leak detection and leaker emission factors for Onshore 

natural gas processing facilities.—El Paso recommends that population count and 

population emission factors apply to dry seal components rather than leak detection given 

this component is designed to emit small amounts of methane.

XVIII. Proposed Rule § 98.233(q)(3) Leak detection and leaker emission factors for Onshore 

natural gas transmission compression facilities.—El Paso requests confirmation from the 

EPA that there are no monitoring requirements for centrifugal compressor dry seals from 

units operated at natural gas transmission facilities. 

XIX. Proposed Rule § 98.233(r) Population count and emission factors. —El Paso 

recommends the use of a facility emission factor to be used as an alternative to population 

count for standard components at processing plants, onshore petroleum, transmission 

compression, underground storage, and LNG import facilities. 

XX. Proposed Rule § 98.233(u)(2)(iv) GHG Volumetric emissions for underground natural 

gas storage facilities.—El Paso requests GHG volumetric emissions for underground natural 

gas storage facilities be based on mole percent of GHG in the natural gas that passes through 

facility. 

XXI. Proposed Rule § 98.233(x) Hydrocarbon liquids dissolved CO2. —El Paso urges EPA to 

limit the applicability of the requirements for dissolved CO2 specifically to onshore oil and 

gas operations that utilize high CO2 content streams for enhanced oil production. 

XXII. Proposed Rule § 98.235 Procedures for estimating missing data.—El Paso requests 

consistent requirements for missing data estimation under Subpart W.

XXIII. Proposed Rule § 98.236(c) Data reporting requirements.—El Paso requests that data 

reporting requirements be limited to data relevant to emission estimates.

XXIV. Proposed Rule § 98.238 Definitions.—Onshore petroleum and natural gas production 

facilities should be renamed “reporting areas” for clarity and correctness. 

XXV. Proposed Rule § 98.6 Definition for Flare Combustion. —A revision to the proposed 

definition is requested for clarity and accuracy.

XXVI. Preamble at Page 18610-11 regarding legal authority.—The Subpart W proposal is in 

excess of EPA’s statutory authority under CAA Section 114; fails to meet the standard of 

reasonableness applicable to requests for information under Section 114; and as proposed, 

would fail to meet the arbitrary and capricious standard of review if challenged. El Paso 

submits the balance of these comments without waiving its objections to the legal basis for 

the rule.
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ATTACHMENT 2

EL PASO’S DETAILED COMMENTS ON THE PROPOSED RULE FOR 

MANDATORY REPORTING OF GREENHOUSE GASES

El Paso submits these comments subject to and reserving its legal objections to the Subpart W 

proposed rule, which El Paso believes goes beyond EPA’s statutory authority under Subpart W; 

and is not a reasonable request for information under Section 114. El Paso’s comments on the 

legal aspects of the Subpart W re-proposal are covered in more detail in Section XXVI of this 

Attachment.

I. Preamble Section II.(A.) on Page 18612 — EPA’s proposed dates for initial data 

collection and initial submittal of reports are not feasible. El Paso requests the EPA to 

consider a June 30 submittal deadline for all emission reports related to Subpart W.

On page 18612 of the proposed rules, the EPA states that the facilities would be required to 

collect data (i.e. conduct monitoring) in 2011 “following the methods outlined in the proposed 

rule, and submit data to EPA by March 31, 2012.” EPA cites the need for data to inform future 

GHG policy and regulatory programs and Congressional intent to develop a reporting program 

on an expedited schedule as reasons for the monitoring and reporting schedule of the proposed 

rule. Also, the preamble of the proposed rule cites that the “EPA considered, but decided not to

propose, the use of best available monitoring methods for part (e.g., the first three months) or all 

of the first year of data collection.” EPA concludes that the time period (i.e. monitoring in 2011 

and reporting by March 31, 2012) is “sufficient to allow facilities to implement the monitoring 

methods that would be required by the proposed rule.” EPA supports its decisions based on the 

following:

1. The proposed monitors are widely available and not time consuming to install;

2. Some of the monitoring methods do not require installation of monitoring equipment;

3. Monitoring can be conducted anytime during the year and not necessarily on January 1, 

2011 or even during the first quarter.

El Paso believes EPA’s reasoning above ignores practical regulatory, legal, technical and 

resource constraints faced by both the reporting entity and the government. By establishing 

such an aggressive schedule, without a transition period allowing for use of best available data, 

EPA has failed, without adequate justification, to give reasonable consideration to an important 

aspect of the challenges presented by the Subpart W rule.

These challenges are outlined below:

A. Unlike EPA Gas STAR voluntary initiatives, the proposed rules require 

significant internal processes and policies to ensure a “compliance grade” program. 

Development of “compliance grade” systems, processes and policies takes time:

It is likely that the final rule will probably be released by third quarter of 2010 and therefore it is 

likely that reporting entities will have only a few months to establish a compliance program. 
Page | 5

All reports have to follow the certification under Section 98.4(e)(1) as below:

"I certify under penalty of law that I have personally examined, and am familiar with, the 

statements and information submitted in this document and all its attachments. Based on 

my inquiry of those individuals with primary responsibility for obtaining the information, 

I certify that the statements and information are to the best of my knowledge and belief 

true, accurate, and complete. I am aware that there are significant penalties for 

submitting false statements and information or omitting required statements and 

information, including the possibility of fine or imprisonment.’’ 

El Paso is the only natural gas company to have reported certified US emissions from natural gas 

production, processing and transmission facilities with CCAR and DOE. We currently operate 

198 transmission compressor stations, 11 processing plants, 40 offshore production facilities, 62 

onshore production fields, and one Liquefied Natural gas (LNG) import terminal. Of these, 156

facilities5 are anticipated to be subject to the proposed rule. 

El Paso will have to account for emissions from over a million discrete components. Despite El 

Paso’s unrivalled experience in emissions accounting and monitoring, we feel that the proposed 

start date of January 1, 2011 is extremely aggressive and will undermine quality of data reported. 

Several features required by the EPA proposal will require us to develop internal policies and 

procedures that will be needed to provide our Designated Representative a reasonable assurance 

of compliance. Compliance with the rules will, therefore, require the development of internal 

control systems and policies in addition to the monitoring and reporting programs required by the 

EPA. Companies may, for example, need to develop robust inventory management plans (for 

monitoring and reporting of emissions), internal audit, QA/QC plans, and similar control systems 

in support of the Designated Representatives’ certification of companies’ inventories.

Such policies and procedures have to be established such that it provides a reasonable assurance 

of compliance to management prior to the signature and submittal of the report per Section 

98.4(e)(1). Other measures faced by companies such as contracts with third party vendors, 

developing monitoring and compliance plans all take time. By requiring initiation of compliance 

monitoring in 2011, the EPA will likely be creating an unsustainable, unverifiable program with 

emissions estimates that are highly susceptible to error.

B. EPA underestimates the time required to develop compliance tools and 

submit:

1. El Paso’s Subpart C “Monitoring Plan” Experience

Detailed analysis of EPA’s cost estimates and El Paso’s projections of the same with respect to 

Subpart W compliance is provided in Appendix II of these comments. 

 5 Estimates based on available data and generally accepted GHG estimation methods. Natural gas exploration and 

production facilities were defined at a “reporting field” level within a “basin” as defined under proposed § 98.238 (i.e., all 

such fields when aggregated emits over 25,000 tons per year). See Appendix II of the comments.
Page | 6

EPA requires a written GHG monitoring plan containing the information specified in 40 CFR 98.3(g)(5).

In relation to compliance with 40 CFR 98 Subpart C, El Paso developed monitoring plans for 71 

transmission facilities, which involved compilation and/or verification of equipment 

specifications for 796 stationary fuel combustion sources. Based on our actual work, our 

collective resource time expended on these monitoring plans were approximately 650 hours, i.e. 

approximately 9 hours per facility.

For Subpart W compliance, monitoring plans would have to be developed for about 156

facilities. This will cover the facilities already identified as subject to Subpart C plus 85

additional facilities. It is estimated that extending existing monitoring plans to the additional 

facilities will take approximately 6 hours per natural gas transmission facility, which will involve 

data gathering and/or QA/QC for approximately 650+ additional stationary fuel combustion 

sources alone. For exploration and production facilities, it is estimated that 10 hours per facility 

will be expended on initial monitoring plan development. It is expected that the development of 

the monitoring plan to comply with subpart W requirements will take considerably longer than 

the monitoring plan for Subpart C due to:

1. Multiple facility categories under Subpart W;

2. Different emission source types at each facility type;

3. Different emission calculation methodologies for different source types;

4. In some cases, more than one emission estimation methodology is available for a specific 

source type;

5. Cooperation from multiple departments (Environmental, Measurement, Plant Services, 

and Operations) will be necessary.

The development of quality monitoring plans for Subpart W is just one example of the myriad of 

new compliance requirements that will be required as part of this rule. Companies such as El 

Paso with facilities in multiple states regulated by the new rule will be required to put into 

motion several practical compliance measures, including development of monitoring plans as 

soon as the rule is finalized. In the Q&As, the EPA estimates that 3 months should be adequate 

to develop a monitoring plan and that the plan may “rely on existing corporate documents like 

“SOPs” and Monitoring Plans developed for compliance with other air programs”. The 

regulation contains the following statement in 98.3(g)(5)(C)(ii):

“The GHG Monitoring Plan may rely on references to existing corporate documents 

(e.g., standard operating procedures, quality assurance programs under appendix F to 

40 CFR part 60 or appendix B to 40 CFR part 75, and other documents)...”

However, for facilities in the petroleum and natural gas sector including facilities meeting the 

definition of a gas processing plant under NSPS KKK, there are no existing air programs that 

require fugitive emission monitoring in a way prescribed in the proposed regulation. Therefore, 

the assumption that a monitoring plan may rely on existing company documents is incorrect. If 

the regulation is finalized in September 2010, only about three months will be available to 

develop and rollout the monitoring plans. Therefore, El Paso suggests for: 1) allowing 

additional time to develop quality monitoring plans for compliance with Subpart W, i.e. at least 

until April 1, 2011; and 2) incorporating similar special provisions for reporting year 2011, as 

currently prescribed under Section 98.3(d), allowing the use of best available monitoring 
Page | 7

methods in the first quarter of 2011 for any parameter (i.e., inlet/outlet metered volumes, GHG 

concentrations of inlet/outlet gas to/from various emissions sources, GHG concentrations of 

underground storage gas, etc.) that cannot reasonably be measured according to monitoring and 

QA/QC requirements of a relevant subpart.

In summary, El Paso requests EPA allow additional time to develop appropriate compliance 

programs and tools required by the new Subpart W rule.

2. Inexperience

GHG accounting is fairly new for most companies outside the electric sector. Most companies 

will require significant resources and time to comply with the regulations. Even if EPA finalizes 

the Subpart W reporting rule by the third quarter of 2010, it will not be possible for the regulated 

community to set up systems and programs within a few months of a final rule nor can the 

regulated community set up the program early due to uncertainties as to what will be included in 

the final rule. El Paso is one of only a few natural gas companies to carry out voluntary 

monitoring and research of fugitive monitoring methods. Moreover, there is no approved, 

standardized protocol to carry out such monitoring. Therefore, once the monitoring methods 

outlined in proposed rule are finalized, reporters will need to ensure that they are familiar with 

the requirements and that appropriate monitoring and compliance plans are developed to ensure 

compliance. El Paso does not believe that implementation of monitoring program and 

completion of all required measurements and monitoring can be accomplished by December 31, 

2011. 

3. Limited Resources & Contractors

Currently the human and technological resources necessary to carry out comprehensive 

monitoring required by Subpart W are limited. Very few personnel within El Paso are currently 

familiar with the monitoring equipment and trained to conduct such measurements. In addition, 

outside contractors familiar with the monitoring devices and in a position to carry out extensive 

monitoring at El Paso facilities are limited to a handful. Per the PRCI report6, over 1500+ 

components can be expected to be monitored per pipeline facility under the EPA proposed rule. 

We have estimated over a million components for our exploration and production business unit. 

Please see Appendix II for additional details. The proposed schedule is, therefore, impossible to 

meet considering practical resource constraints.

4. Monitoring Program Implementation Challenges

a) Safety - Leak measurements at natural gas compressor stations 

are conducted in an environment with numerous safety challenges:

The proposed schedule is too aggressive to allow regulated entities and their contractors to 

adequately train the field employees who will do the actually monitoring work. Training is 

required in important safety measures to keep sampling personnel safe, and sampling techniques 

 6 PR-246-9526, T. Howard, R. Kantamaneni, and G. Jones December 1998
Page | 8

to help ensure the data collected is reasonably accurate. In addition, transportation and schedule 

will present significant challenges on the aggressive schedule EPA has proposed.

1) Possibility of explosive concentrations. Any work in a facility will require either

equipment of a type referred to by safety professionals as “intrinsically safe” equipment or 

a “Hot Work” permit (which requires periodic screening to verify that gas concentrations in 

the area of work remain below safe levels). Leak measurements require that personnel 

specifically go to the area where explosive concentrations are most likely to be present. 

This is particularly true on measurements for vented components where leak rates are 

potentially larger than at standard components, which could result in explosive 

concentrations of gas in the air around the personnel during sampling. It is critical that 

personnel are properly trained how to remain safe in such environment. Examples of 

hazards include bringing manlift bucket circuitry (which is usually not intrinsically safe) 

within the gas cloud, striking the steel vent pipe with any material which might cause a 

spark (including being bumped by the manlift or by metal fittings on harnesses), losing 

control of a vent bag filled with natural gas, which could be blown onto a hot surface such 

as an exhaust stack and combust, or inadvertently venting natural gas through the HighFlow Sampler to a location where large concentrations are not expected. Static electricity 

discharges may also be a risk factor.

2) Fall Risk. Measurements at elevated vents require personnel to use man-lifts, ladders, or 

roof access, usually on sloped roofs. This requires training in fall protection equipment 

including harnesses and lanyards and proper tie off techniques. The installation of taps 

into the vent stacks inside the building or at a location more easily accessible near ground 

level would eliminate fall risk. But the installation of these will take considerable time to 

complete for compressors that are anticipated to be applicable to Subpart W monitoring 

requirements (approximately 1,315 at El Paso’s facilities alone). In addition, tag and lockout procedures on the downstream compressor units would be needed to prevent the 

presence of natural gas during the vent stack piping modifications which typically could 

only be done during the limited maintenance window discussed in the section below. 

3) High Pressure Gas. Hazards involve the possibility that a component will break off and 

vent gas during sampling or that a blow down will occur at a vent while it is being 

measured. Injury could result should a measurement specialist have his head or hands in 

the path of the blow down. Personnel must also be trained properly so that vents such as 

rod packing vents are not subjected to any significant back-pressure, which could cause 

safety or operational problems.

4) High Temperatures. The risks from high temperatures include burns from touching hot 

components as well as heat exhaustion from working near high temperature sources.

5) Moving machinery. Many components are either constantly moving or can move due to 

remote activation and can cause serious injury should clothing or a body part be caught in 

the system.

6) Air Toxics. Measurements at condensate tank vents require additional respiratory personal 

protective equipment due to the heavier hydrocarbons that may be venting from the tank.
Page | 9

b) Measurement Complexities - Although simple in principle, the 

proposed measurement techniques require substantial experience to 

perform correctly. Considerations include:

1) Hi-Flow enclosures must be placed so as not to restrict air flow and allow full capture of 

leaks. 

2) The background probe for the H-Flow sampler must be placed in the correct position to 

determine if there is any interference from other sources as well as to determine whether or 

not complete capture of the leak has been achieved.

3) The vent bag technique must be first practiced under metered conditions in order to be 

confident of the results. Personnel must be aware of how to eliminate potential errors due to 

leaks, restricted openings, or flow induced by Venturi effects. 

4) Some vents may be manifolded together, sometimes going to a larger diameter (six feet) 

silencer. Larger diameter vent stacks have been measured previously with the use of covers, 

but this technique requires practice and great attention to safety considerations. It may not be 

possible to know which source is the leak in these cases. 

c) Transportation, scheduling, and maintenance issues – Pipelines 

and Production Facilities

The proposed rule requires that for each compressor rod packing one measurement in each of the 

operational modes that occurs during a reporting period is conducted, 98.233(p)(4). However, 

there is only a limited window for performing routine maintenance on an interstate pipeline 

system. Performing measurements in all three modes of operations will require potentially 

stopping and blowing down compressor units7

, and starting a unit that is idle8, which due to 

safety issues mentioned in Section I(B)(4)(a) of these comments, must be scheduled with or in 

addition to other routine maintenance activities9

 

. For example, on the Tennessee Gas Pipeline

(TGP) system, per the tariff, the window for performing routine maintenance would be from

7 Typically during maintenance of a compressor unit, the engine is blown-down for safety reasons. In addition, if it 

is determined that the unit isolation valve is leaking at a rate of concern for operations and maintenance personal, 

our safety practices would require that further actions be taken to reduce the leak rate. This would first include 

actions such as re-greasing the unit isolation valve. In limited cases, this may not be sufficient to reduce the leak so 

the second practice would include putting in a blind flange in the piping to remove the concerns raised by the 

leaking unit isolation valve. Blind flanges would also be used in the unusual case involving the complete removal of 

compressor unit for maintenance.

8 The risk of arbitrarily starting a unit to avoid a certain mode of operation during a survey, such as idle-depressurized, is 

minimal because: 1) This would require compressor operation in recycle mode (assuming a recycle valve was available for 

opening) which in turn causes risk of overheating the compressor; and 2) Since El Paso typically operates their pipelines 

near maximum allowable operating pressure (MAOP), a unit start-up requires that a second unit be stopped to prevent 

pipeline pressure and flow increases from occurring unless there was an immediate increase in customer demand.

9 Per El Paso’s Compressor Operation Policies and Procedures (COPP) Manual, mechanical inspections on reciprocating 

engines must be completed at a maximum 16,000 hours or 48 month interval. Major overhauls on turbines are required 

every 30,000 – 48,000 hours depending on turbine manufacturer. Minor inspections on both engine types can occur every 

4,000-8,000 hours.
Page | 10

May through October. Dual peaking for demand (summer and winter) is met via natural gas fired 

compressor units. 

Peak power loads occur in July through August where 90% of the peak needs are met through 

natural gas fired turbines. To prevent supply problems in the winter months, the storage fields 

need to be full by November 1 of each year. Billions of cubic feet of natural gas must be 

transported and injected into storage prior to the winter heating season. 

It is incredibly difficult to schedule down-time for a compressor station on a gas pipeline system. 

Per the tariff, customers must be informed of any maintenance during the peak season. In fact, 

schedules are available publicly and can be found at: 1) The following link for each El Paso 

pipeline subsidiary: http://elpaso.com/postings/default.asp; then 2) Reference links on side bar 

titled “Notices” and “Planned Service Outage”.

In addition, demand can change quickly and without prior notice. At any point, multiple 

compressor stations may need to respond quickly to changing load (or demand for natural gas) 

conditions with other multiple compressor stations. Some cities have only a single source of 

natural gas to rely on. Having a compressor station down can result in considerable loss in 

capacity. For example, for a typical mainline compressor station this could mean a 200 million 

cubic foot a day loss in capacity. Further scheduling complications for conducting direct 

measurements will result for the stations that are unmanned and remotely controlled. 

Approximately 27% of El Paso’s facilities, located across 42,000 miles of interstate pipeline, are 

currently manned 24 hrs/day, 7days/wk. 

The demand on upstream compressors at exploration and production (E&P) facilities is even 

greater, thereby shortening the window to conduct maintenance. The movement of upstream 

compressors from one location to another will complicate further scheduling issues. This 

coupled with the fact that these compressors are dispersed over a wide geographic area (10 states

for El Paso’s E&P) limits the ability to opportunistically conduct the necessary measurements in 

each mode of operation. Therefore, location-based schedules will need to be developed for each 

of these compressors. Reciprocating compressors located at well heads or field gathering 

compression, typically do not have back-up equipment. This will require that a compressor be 

deliberately shut down for GHG measurements. Significant costs to E&P companies will be 

incurred due to the loss of production during these deliberate shut downs. (Note, these costs are 

not represented in El Paso’s alternative cost analysis provided in Appendix II, but would be 

additional to the average $732,713 cost for a basin level reporting unit.) It is important for the 

EPA to recognize that when an upstream compressor is down there are typically other activities 

such as maintenance or a compressor move simultaneously occurring. Attempting to conduct 

GHG measurements simultaneously with these activities poses additional safety risks to all 

involved employees and contractors. 
Page | 11

As noted earlier, El Paso operates about 156 facilities potentially subject to the proposed rule. 

Most natural gas facilities are located in remote locations and comprise of thousands of relatively 

small sources (especially those that are sources of fugitive emissions). These facilities often lack 

the automation to facilitate data collection, retention, analysis and quantification of the GHG 

sources (especially fugitive emission sources). Therefore, GHG accounting in our sector will 

continue to rely primarily on manual processes for the intermediate future. 

El Paso has taken over 4 years and expended over $1.5mm to develop a “verifiable grade” 

inventory for reporting to DOE and CCAR emissions from our US Operations (Figure 1 and 

Table 1). These costs relate primarily to developing emissions estimates and reporting and do 

not include comprehensive monitoring program proposed by the EPA under Subpart W. By 

failing to consider these costs, EPA has disregarded an important aspect of the challenges

presented by compliance with the proposed Subpart W.

Table 1: El Paso’s Costs on GHG Emission Inventories (in US $)

Task 2005 2006 2007 2008 Total

IT/Data base 0 39,406 182,742 115,539 337,686

Inventory, Verification 135,771 244,746 390,984 362,817 1,134,318

Policies & Procedures 5,755 53,723 6,027 3,453 68,958

Grand Total 1,540,962

 Figure 1: El Paso’s Costs on GHG Emission Inventories

Our CCAR submittal in 2008 required over 2700 staff hours to complete the necessary data 

gathering and analysis, despite three consecutive years of preparing US GHG inventories. This 

level of effort shows that while we can expect efficiency improvements as we gain experience 

with GHG reporting, the resources and the time required to complete an emissions inventory are 

GHG Emission Inventory Costs

0

100,000

200,000

300,000

400,000

500,000

600,000

700,000

2005 2006 2007 2008

IT/Data base Inventory, Verification Policies & Procedures
Page | 12

still substantial even after a number of years. Given that EPA’s reporting protocol differs both 

from the CCAR and the DOE programs, new policies, procedures and systems need to be 

planned and developed for compliance with the EPA reporting rule. This planning will take 

significant time for even experienced companies like El Paso. And even after the necessary 

process optimization and experience, computation of emissions from El Paso facilities, 

especially those subject to proposed Subpart W, cannot be completed in one quarter after the end 

of the calendar year, for the above mentioned reasons. Therefore, we request that EPA consider 

a June 30 submittal deadline for all emission reports related to Subpart W.

II. Preamble Section II.(C.) on Page 18613, Definition of the Source Category for 

Onshore Petroleum and Natural Gas Production 

Under a number of provisions of the Clean Air Act, the term “facility” has a specific meaning as 

a “group of emissions all located in a contiguous area and under the control of the same person 

(or persons under common control).” As EPA notes in the TSD, this definition can be easily 

applied to onshore natural gas processing and petroleum refining facilities, which are located in a 

clearly defined boundary. EPA also notes that this definition does not directly lend itself to 

onshore petroleum and natural gas production, onshore natural gas transmission pipelines and 

natural gas distribution sectors. Therefore, to avoid confusion, the EPA should utilize the term 

“reporting area” rather than “facility” in referring to the geographical area used to assess 

emission thresholds for onshore oil and gas production.

III. Preamble at 18618 and 18625, Economic Impacts of the Proposed Rule Support 

Reporting on a Field Basis as Opposed to Cost Prohibitive Basin Approach

El Paso supports commenters, such as the American Exploration and Production Council, who 

urge EPA to use the traditional definition of facility for oil and gas activities, rather than either 

the field-level or basin-level approaches proposed. As between field-level and basin-level 

reporting, El Paso recommends that EPA employ the applicability threshold for exploration and 

production based on applicable sources located within a reporting field or area that in the 

aggregate emits over 25,000 metric tons per year. Through this rule development, in determining 

the appropriate threshold and “facility” definitions, EPA must balance the coverage in terms of 

emissions with the regulatory and cost burden to both industry and the regulatory agency. 

Table W-2, on page 18618 of the preamble, indicates that at a proposed 25,000 metric tons

threshold, about 81% of the emissions are covered by employing the applicable facility defined 

at “basin” level. However, as outlined in Table W-3 on page 18619, EPA concludes that about 

55% of the emissions are covered by employing a facility definition at a reporting field level.

El Paso has been unable to reproduce EPA’s emissions or cost basis due to lack of information 

provided in various support documents associated with the rule. The preamble is the first public 

document where EPA has revised its estimates of the total emissions from the natural gas sector. 

EPA has not given reasonable consideration or explanation of the costs of including E&P in the 

monitoring and reporting rule requirements.

El Paso believes that EPA has significantly underestimated the level of effort and cost 

implications for Subpart W, especially as it applies to onshore oil and gas production operations. 
Page | 13

However, it is difficult to compare internal estimates of the cost impacts to EPA’s assumptions, 

given that the Economic Impact Assessment (EIA), Technical Support Document (TSD), or 

information available on the Docket are not consistent with the basin-level facility definition or 

do not provide sufficient detail to evaluate EPA’s cost assumptions. El Paso developed a 

detailed cost estimate for our E&P operations and the number of sources associated with our 

upstream operations for two reporting unit scenarios: (1) basin > 25,000 metric tons; and (2) field

>25,000 metric tons. The detailed cost analysis has been included in Appendix II. Figure 2

presents estimated costs for El Paso’s onshore oil and gas production operations relative to the 

percent of total emissions and number of regulated fields for each of the three reporting area 

scenarios. Essentially, 98% of the emissions are covered at the basin level but at over twice the 

cost of covering El Paso facilities at a reporting field basis.

Figure 2: El Paso’s Estimated Compliance Costs for Three “Reporting Area” Scenarios

A. Basin Reporting Unit >25,000 metric tons CO2e:

El Paso constructed a detailed cost analysis on a source-by-source basis for all of its 

operations that exceed 25,000 metric tons CO2e at the basin level. For the upstream 

operations only, the proposed rule will require that more than 1 million individual emission 

sources be measured or documented in order to quantify and report emissions. El Paso has 

examined the level of effort expected to gather data specified for onshore oil and gas 

production operations. Our estimates show that first year compliance for Subpart W will 

require over 25 full time equivalents10 (FTE). Subsequent years will require 17.1 FTEs. 

Based on our estimates for the basin-level reporting unit, the emission sources with the 

largest compliance burden are 10K thresholds.

 10 FTE based on 2000 hours/year.

0%

10%

20%

30%

40%

50%

60%

70%

80%

90%

100%

Basin > 25K Field >25k Field >10k

% of Emissions

0

10

20

30

40

50

60

70

# of Fields

% of Emissions

 # of Regulated Fields

$6.6MM

$3.1MM

$5.6MM
Page | 14

• Dissolved CO2: 8.57 FTEs to comply (for both Year 1 and subsequent years);

• General activities to develop data management systems and processes (including 

training) to gather, report, and monitor the required information: 4.58 FTEs for Year 

1, 2.65 FTEs for subsequent years.

• Tanks: 3.75 FTEs for Year 1, 3.21 FTEs for subsequent years. 

• Gas well workovers and completions (conventional and unconventional combined): 

1.08 FTEs for Year 1 and 0.59 FTEs for subsequent years. 

• Well venting for liquids unloading: 1.05 FTEs for Year 1 and 0.62 for subsequent 

years. 

• Reciprocating Compressor Rod Packing Vents: 0.71 FTEs for Year 1, and 0.67 FTEs 

for subsequent years.

For a reporting unit defined as a basin > 25,000 metric tons CO2e, El Paso has 9 such basinlevel reporting units comprised of 60 E&P fields, with an average first-year cost of $732,713 

per basin.

B. Field Reporting Unit >25,000 metric tons CO2e:

For comparison, El Paso also examined the costs and emissions coverage based on defining 

the E&P reporting unit at a production field level emitting > 25,000 metric tons CO2e (these 

details are also provided in the cost analysis spreadsheet). This approach captures 65% of 

emissions from El Paso’s E&P operations, but reduces the reporting burden to a total of 15 

production fields at an average cost of $206,000 per field. Emissions associated with fields 

not covered by the provisions of the proposed rule, could be estimated by applying simple 

emission factors to production rates or estimates of major equipment.

Based on the field level approach and 25,000 metric tons threshold, the estimated first year 

compliance will require 9.9 FTEs and 7.9 FTEs for subsequent year compliance efforts. 

Table 2: Comparison of El Paso and EPA Cost Estimates

1.

2.

3.

4.

5.

6.

Year 1 Costs/Facility Year 2 Costs/Facility

 

 

 

Basin 

>25k 

MT/year

Field > 25k 

MT/year

Basin >25k 

MT/year

Field > 25k 

MT/year

Facility Count 9 15 9 15

El Paso $732,713 $205,650 $546,810 $160,106

EPA $44,367 No Estimate $13,691 No Estimate
Page | 15

C. Reporting Level Conclusions and Recommendations:

Based on the detailed cost analysis performed using inventory information rooted in three years 

of third-party verified voluntary emissions inventories, El Paso supports a production field level 

approach and 25,000 metric tons CO2e per year threshold. The quality of emissions information 

gathered would be better for field-level data rather than basin-level data. Characteristics of the 

produced oil and gas, method of separation and processing are more closely aligned with the 

field from which the oil and gas is produced than from a broader basin perspective. El Paso has 

been compiling GHG emission inventories at the field level since 2006, using field designations 

that are similar to that of the Energy Information Administration. We believe this approach 

balances both coverage and regulatory and compliance burden.

IV. § 98.231 Applicability Analysis: EPA must provide flexibility to regulated facilities 

with respect to applicability determination of Subpart W rule. El Paso proposes two 

screening methods to assist with determination.

EPA has not proposed a “screening” method to determine initial applicability to the rule but 

instead relies on EPA proposed monitoring methods to make the determination of applicability to 

the rule (per Subpart A provisions). The lack of a proposed screening method is a significant gap 

with respect to an important aspect of compliance with Subpart W for entities that do not 

currently have data collected using EPA’s proposed methods (which we believe, will be most 

entities). El Paso proposes two alternative screening methods:

1) A 10,000 metric tons CO2e threshold established based on combustion emissions 

using procedures outlined in Subpart C; or

2) Allow use of best available data to estimate GHG emissions and determine 

applicability against 25,000 metric tons CO2e threshold.

In addition, we request that EPA include a safe-harbor provision under both cases.

A company would have to conduct proposed monitoring at all its facilities to assess applicability 

to the rule. Our current estimates of 156 facilities potentially subject to Subpart W are based on 

the use of best available methodologies gained through our participation in the California 

Climate Action Registry (CCAR) and Department of Energy 1605(b) emissions inventory 

programs.

Without a screening method to assess initial applicability, a company like El Paso with potential 

of over 150 applicable facilities operating in multiple states is subject to significant uncertainty 

related to the actual applicability of the rule to its facilities. Such uncertainties will result in 

significant compliance burden and hamper effective compliance planning.
Page | 16

A. Screening at 10,000 metric tons threshold based on Subpart C emissions:

We recommend that EPA permanently establish a “screening” threshold of 10,000 metric tons

CO2e per year based on emissions from combustion. That is, any facility with combustion 

emissions (Subpart C) less than 10,000 metric tons would not be subject to Subpart W. We feel 

this initial screening threshold is justifiable since repeated inventories conducted by the EPA 

indicate methane emissions are approximately half of the total emissions from the natural gas 

sector, and 10,000 metric tons is less than half the 25,000 metric tons threshold for the 

monitoring and reporting rule. EPA estimates over 351 million metric tons11 from facilities 

subject to the proposed rule and over 415 million metric tons12 from the entire sector. While 

these estimates are almost double of EPA’s official inventory13 presented below in Table 3, the 

breakdown between methane and CO2 related emissions remain at about 40% to 60% for the 

overall natural gas sector. Therefore, a 10,000 metric tons threshold based on combustion 

emissions is justifiable and provides adequate buffer considering the reporting threshold of 

25,000 metric tons. Such a “screening” threshold will enable companies to focus on potential 

major sources and not divert significant resources to confirming applicability or nonapplicability of smaller facilities.

This approach of basing initial screening on a 10,000 metric tons Subpart C threshold is El 

Paso’s preferred approach in that it presents a relatively clear, easily enforceable screening tool. 

In the alternative, EPA could consider a screening approach based on best available data, as 

outlined below. The 10,000 metric tons Subpart C screening method is, however, El Paso’s 

preferred approach due to its clarity and ease of application.

B. Screening based on best available data:

In the alternative, until monitoring has been conducted at a facility, EPA should allow potentially 

affected Subpart W sources to employ best available data at a facility or onshore production 

“reporting area” level to estimate GHG emissions and determine applicability against the 25,000 

metric tons threshold based on the estimated emissions. The best available data includes 2006 

IPCC Guidelines, U.S. GHG Inventory, DOE 1605(b), The Climate Registry, California Climate 

Action Reserve and corporate industry protocols developed by the American Petroleum Institute, 

the Interstate Natural Gas Association of America, and the American Gas Association and 

measurement data developed internally by the reporters. 

Companies should be allowed to use these best available to estimate total emissions from 

facilities or onshore production reporting areas for which monitoring at Subpart W facilities has 

not yet been conducted, either because the rule is new or because the facilities have not yet been 

estimated to exceed 25,000 metric tons based on best available methods. Companies should be 

permitted to employ the estimated results to decide whether those facilities that have emissions 

 11 Preamble Page 18612 12 Economic Impact Analysis for the Mandatory Reporting of Greenhouse Gas Emissions under Subpart W 

Supplemental Rule (EPA– HQ–OAR–2009–0923). Table 4-6. 13 EPA Inventory of U.S. Greenhouse Gas Emissions and Sinks 1990-2008
Page | 17

over 25,000 metric tons. Once a facility’s estimated emissions based on best available methods 

exceed 25,000 metric tons, the first year monitoring methods would be carried out per the final 

rule at these “screened” facilities and reports for the first year will be from these facilities that 

have been “screened” to emit over 25,000 metric tons CO2e. 

C. Safe harbor provision for screening methods:

Finally, El Paso requests a “safe harbor” provision be added under the final Subpart W rules. 

As explained above, the proposed methods will employ screening techniques for applicability 

determination in the first year. El Paso requests that EPA promulgate a safe harbor provision for 

companies using any reasonable screening techniques. EPA can draw from such prior regulatory 

precedence granted by the Federal Energy Regulatory Commission (FERC). The FERC granted 

a one-year safe harbor provision after issuing Order No. 704, which requires the reporting of 

natural gas transactions (FERC Form No. 552). This allowed the respondents to “benefit from a 

rebuttable presumption that the data provided is accurate and submitted in good faith. Further, 

we [the FERC] do not intend to penalize respondents for errors in reporting on Form No. 552 

provided that respondents use reasonable efforts to comply with the regulations regarding and 

instructions for Form No. 552. We [the FERC] emphasize that the Commission expects 

respondents submitting Form No. 552 in 2009 to do so in good faith and on a timely basis.” 

Such safe harbor provision will provide the necessary certainty for companies while limiting the 

risk of potential retroactive enforcement in the event a facility initially determined not to be 

applicable to Subpart W based on the screening methods, results with emissions > 25,000 metric 

tons CO2e using EPA’s final monitoring and estimation methods.

V. § 98.232 GHGs to report: Considering practical concerns in complying with a 

March 31, 2012 initial reporting deadline, El Paso recommends a “transitional” program to 

phase in affected Subpart W facilities into full reporting per EPA final methods by 2015. 

Due to the time constraints and monitoring implementation challenges previously mentioned, El 

Paso recommends a phased-in approach that will transition to full reporting using EPA methods 

by 2015. As noted below, our recommendations are meant to transition into meaningful and 

accurate reporting while considering practical issues in estimating and reporting emissions to 

meet EPA’s planning needs.

A. A transitional plan for the natural gas sector will have minimal overall 

impact to EPA and/or Congress’s future programs related to GHGs. 

Figure 3 indicates that over 85% of the U.S. emissions are combustion related and most of these 

emissions will be reported under existing finalized EPA reporting methods under Subpart C. 
Page | 18

Figure 3: 2008 Greenhouse Gas Emissions by Gas (percents based on Tg CO2 Eq.). Reproduced 

from Figure ES-4 EPA Inventory14

Table 3: 2008 Greenhouse Gas Emissions for the Natural Gas Industry and the U.S.

(Tg CO2 equivalent)

Energy 

Related 

CO2

Emissions

NonCombustion 

CO2

Emissions

CO2 CH4 Total 

CO2e

Production 47.5 8.5 56.0 14.1 70.1

Processing 19.5 21.4 40.9 13.0 53.9

Transmission and Storage 35.4 0.1 35.5 39.4 74.9

Distribution 0 0 0.0 29.9 29.9

Gas Industry Total 102.4 30.0 132.4 96.4 228.8

U.S. Total 5,905.5 567.3 6,946.1

Gas Industry Share of U.S. 2.2% 17.0% 3.3%

Transmission Share of U.S. 0.6% 6.9% 1.1%

 14 EPA 430-R-10-006, INVENTORY OF U.S. GREENHOUSE GAS EMISSIONS AND SINKS: 1990 – 2008, 

APRIL 15, 2010
Page | 19

As noted in Table 3, the total natural gas industry’s share, including combustion, of the US 

emissions is about 3.3% with combustion emissions that are already planned to be reported under 

Subpart C at over 57% of the total natural gas system profile. In other words, per this EPA 

inventory15, about 43% of the emissions are intended to be regulated under proposed Subpart W. 

Even if the current estimation methodologies have uncertainty (e.g. compressor stations at 50% 

uncertainty per Table 4), it would have minimal impact - about 48 million metric tons of 

maximum under-statement per the official EPA inventory and uncertainty factors developed as 

part of previous rulemaking- to overall future greenhouse gas plans for the entire country. It 

should be clearly noted that even the proposed EPA methods have significant uncertainties.

Table 4: Uncertainty Estimates by Methodology 

Source: Table 5-9, March 2009, Regulatory Impact Analysis for the Mandatory Reporting of Greenhouse Gas Emissions Proposed Rule 

(GHG Reporting), Final Report

As noted earlier, EPA states that one of the main reasons for a March 31, 2012 comprehensive 

report for Subpart W sources is its need to develop future GHG policy and regulatory programs 

[for natural gas systems]. 

Current legislative proposals, if enacted, would pre-empt EPA authority under Clean Air Act and 

instead control GHG emissions, including emissions from natural gas systems, under a new 

statutory program. El Paso’s alternative proposals outlined below will provide the appropriate 

emissions data to EPA for its future stated purposes of, among other things, informing the 

legislative process. El Paso’s suggested alternative will also help reduce the significant potential 

 15 EPA has stated that the inventory developed under EPA 430-R-10-006 under estimates methane related emissions 

from the natural gas sector, yet this is the same inventory used in all current legislative bills and forms the basis in 

all international negotiations including the Copenhagen Accord.
Page | 20

for error and enforcement concerns of the proposed Subpart W program for both EPA and the 

regulated communities.

We urge the EPA to consider reasonable transition approaches for Subpart W applicable

facilities as outlined below. 

El Paso recommends two temporary transition alternatives to phase in reporting for Subpart W 

facilities. These recommendations arise from our concerns related to timing and expectations of 

this proposed rule and are necessary to enable industry to gain experience and safely collect and 

report emissions data that are reasonably accurate and meaningful and useful for the EPA. These 

transition provisions will be more than adequate for EPA to receive emissions reports from such 

facilities and use the reports received to plan for future programs--including improving Subpart 

W methods.

1. Limiting Approach

Under this approach, for the March 2012 report, the EPA will require only facilities that are 

subject to Subpart C, to report all their GHG emissions including their Subpart W sources using 

final EPA monitoring and reporting methods. Under this approach, the 2012 reporting will be 

limited to sources that are over the 25,000 metric tons threshold for Subpart C. Thereafter, 

additional facilities will be added to the monitoring requirements over the next three years so 

that, by March 2015, all subject facilities will report using the methods specified in EPA’s final

rule. This concept is outlined in Table 5.

Table 5: Limiting Approach

Reporting 

Year

Reporting Facilities GHG Emission Sources

2011 All “facilities” subject to Subpart C All Subpart C and W sources identified 

by the EPA in final rule for the 2011

facilities.

2012 2011 facilities + 1/3 of the remaining 

facilities over 25,000 metric tons in 

combined emissions

All Subpart C and W sources identified 

by the EPA in final rule for the 2012

facilities.

2013 2011 facilities+ 2/3 of the remaining

facilities over 25,000 metric tons in 

combined emissions

All Subpart C and W sources identified 

by the EPA in final rule for the 2013 

facilities.

2014 All facilities over 25,000 metric tons in 

combined emissions

All Subpart C and W sources identified 

by the EPA in final rule for the 2014 

facilities.
Page | 21

2. Phased in – “Hybrid” Approach: EPA Method + Best Available 

Data/Methods

Under this approach, EPA will receive emissions reports from all facilities over 25,000 metric 

tons. In 2012, 75% of the affected facilities owned or operated by a reporter will use standard

industry recognized methodologies (i.e., API Compendium, INGAA Guidelines, etc.) or internal 

monitoring data to report its emissions. The remaining 25% of the facilities will adhere to the 

final EPA required methods for monitoring and reporting. As noted in Table 6, by 2015, all 

facilities will transition to reporting using EPA methods. 

Table 6: Phased-in “Hybrid” Approach 

100% Reporting of Facilities over 25K MT/yr CO2e

Reporting Year Reporting Method for Subpart W Sources

2011 75% - Industry methodologies/best available data

25% - EPA final methods

2012 50% - Industry methodologies/best available data

50% - EPA final methods

2013 25% - Industry methodologies/best available data

75% - EPA final methods

2014 All facilities use EPA methods

The advantage of this is that EPA will receive emissions data for planning purposes from all 

facilities over 25,000 metric tons. All Subpart W methods have associated uncertainties. We 

have already established that using conservative EPA estimates of an overall uncertainty of 

50%16; therefore, the net impact of using industry best available methods for reporting is 

negligible for immediate EPA planning. This hybrid approach provides EPA a fair assessment of 

the emissions from the regulated facilities while allowing regulated facilities gain experience and 

set up programs and policies to achieve full reporting by 2015. 

VI. § 98.232(b) GHGs to report for offshore petroleum and natural gas production

There is a significant disadvantage in the reporting requirements for onshore versus offshore 

operators, even though similar emission sources and practices are used. This difference is not 

explained in the TSD or the proposed rule preamble. 

For offshore oil and gas production, the GOADS program relies on counts of emissions sources, 

volumes of throughputs from significant pieces of equipment, and parametric data to account for 

non-combustion emissions. This is in sharp contrast to the requirements proposed for onshore oil 

and gas production operations. In addition, since the Mineral Management Services only collects 

GOADS data once every three years, the EPA proposes that offshore operators scale emissions based 

on changes in production rates for the interim years. 

 16 Assuming here that EPA proposed methods have no uncertainty and all natural gas systems have an overall 50% 

uncertainty in existing methodologies.
Page | 22

Onshore operators should be allowed to use similar methodologies based on throughputs and counts 

of major equipment. In addition, onshore oil and gas production operations should be allowed to 

scale emission estimates for two out of three reporting years. 

VII. § 98.233 Calculating GHG emissions

Efforts to reduce lost gas have been a driver for companies to implement component 

replacement/repair programs. Management of this program requires that pre- and post-leak 

measurement readings be taken to justify Operation and Maintenance (O&M) costs and confirm 

fugitive emission reductions. EPA should consider that when additional direct measurements of 

emissions for any component are available, the operating company could optionally use multiple 

measurement results obtained during the reporting year to calculate annual emissions for the 

component surveyed per the company’s other reporting procedures for the prioritization of 

related leak reduction work.

VIII. § 98.233(a) Natural gas pneumatic high bleed device venting

Sections 98.233 (a) and (b) require the use of either manufacturer’s data for high bleed 

pneumatics or the application of an emission factor for low bleed pneumatics. However, 

identifying the model of a particular device may be difficult if name plates are obscured by paint 

or wear. Additionally, some units may have been modified over time to reduce their bleed rate, 

but accurate records of these modifications may not be available. 

The EPA should provide a default leak rate that can be used for those devices where the 

manufacturer or model number is not known. Alternatively, the EPA could allow operators to 

use appropriate factors from sources such as the API Compendium to obtain factors for these 

particular devices. As an additional option, the Hi-Flow sampler or similar device could be used 

to make a measurement of the bleed rate from pneumatic devices. If companies already have 

this technology in house or are having it contracted for other measurements at their sites, this 

could provide a method to obtain data that might otherwise be hard to get. The key here is to 

ensure flexibility in monitoring options.

IX. § 98.233(d) Acid gas removal (AGR) vent stacks

The proposed rule requires the following parameters for characterizing emissions from AGR:

• Metered natural gas inlet volume;

• Metered natural gas outlet volume;

• Volume weighted CO2 content of inlet gas;

• Volume weighted CO2 content of outlet gas.

Industry standard practices or current applicable regulations do not require continuous 

monitoring of natural gas flow and volume weighted CO2 content of the gas in and out of the 

AGR. Typically, for an AGR, natural gas inlet volume is the only parameter monitored. El 

Paso’s recent cost estimate indicates it would cost more than $115K to install a metering facility 

to measure the inlet and outlet volumes for one amine unit. Given this high cost, an option to use 

estimated natural gas inlet and outlet volumes should be allowed. 
Page | 23

X. § 98.233(e) Dehydrator vent stacks

Industry standard practices or current applicable regulations do not require continuous 

monitoring of pressure, temperature, flow rates and circulation rates for sources such as 

dehydrators and storage tanks. Typically, for a dehydrator, temperature and pressure at the 

reboiler are the only parameters monitored. The proposed rule requires the following parameters 

for characterizing emissions from dehydrators:

• Natural gas flow rate; 

• Feed natural gas water content; 

• Outlet natural gas water content; 

• Absorbent circulation pump type(natural gas pneumatic/ air pneumatic/ electric); 

• Absorbent circulation rate; 

• Absorbent type; 

• Use of stripping natural gas; 

• Use of flash tank separator (and disposition of recovered gas); 

• Hours operated; and 

• Wet natural gas temperature, pressure, and composition. 

It is El Paso’s interpretation that engineering estimates can be used for the operational 

parameters used to run the GlyCalc model since the rule does not specify metering and 

monitoring for these parameters. El Paso requests confirmation of this interpretation. In 

addition, El Paso requests that dehydration units with a throughput of less than 10 million scf/day 

be excluded from reporting under Subpart W or be permitted to apply a default emission factor 

from the API Compendium in place of conducting modeling using process simulations.

XI. § 98.233(g) Gas well venting during unconventional well completions and workovers

El Paso estimates that it would have to report emissions for approximately 3,500 unconventional 

and conventional completions or workovers using the basin level reporting threshold.

EPA assumes that the majority of unconventional wells are completed with hydraulic fracturing. 

The proposed rule details two different methodologies for estimating emissions from 

unconventional well completions or workovers:

• Method #1 requires the measurement of flow rate during clean-up for one well completion 

and one well work-over in each field. From this a flow rate per minute is derived and applied 

to the minutes of flow-back from each completion and work-over in a field. 

• Method #2 requires monitoring across the completion choke and calculation of flow rate 

during clean-up for one well completion and one well work-over in each field. From this a 

flow rate per minute is derived and applied to the minutes of flow-back from each 

completion and work-over in a field. 

The TSD considered a third method for determining emissions from completions and workovers. 

Method 3 is based on the daily gas production rate, the amount of venting time, and the 

composition of CH4 and CO2 in the produced gas. This approach uses information commonly 
Page | 24

tracked from completion and workover activities and should be included as an alternative 

method in the rule.

XII. § 98.233(i) Blowdown vent stacks

The proposed regulation requires first aggregation of blowdown volumes at actual conditions 

from all events at the facility and then the conversion of the total volume to standard conditions. 

The regulation fails to take into account that each blowdown event may occur at a different 

pipeline pressure and a different gas temperature. In practice, the blow-down volumes are

corrected to standard conditions for each event and then aggregated. Having the order of 

calculations as proposed would result in having to use a pressure of MAOP (Maximum 

Allowable Operating Pressure) and perhaps yearly average temperature at the site which would

probably result in an over predictions of the blowdown volumes. Therefore, El Paso recommends 

that the reporters be allowed to correct the blowdown volumes to standard conditions on a per 

event basis.

Further, the proposed methodology is based on an assumption that the total volume between the 

isolation valves is blowdown. In practice, frequently a blowdown continues only until a desired 

working pressure is achieved. The desired working pressure may differ for each blowdown 

event depending on the reason for the blowdown. Therefore, treating each blowdown event 

individually and considering the initial and ending pressures will result in more accurate 

emission estimates.

It should be noted that many companies currently employ algorithms and programs to calculate 

and document blowdowns, and these methodologies use the same ideal gas law principles as 

intended by the Subpart W equations to calculate “event-based” blowdown volumes. Companies 

currently employing equivalent methods should be allowed to use their methodologies for the 

purpose of reporting GHG emissions under Subpart W.

In addition, El Paso recommends an option be provided for the installation of permanent meters 

on blowdown vent stacks. 

XIII. § 98.233(j) Onshore production & processing storage tanks

El Paso estimates that gathering the data necessary to comply with the requirements for onshore 

storage tanks is one of the most costly sources relative to the emissions contribution. EPA has 

not considered this important aspect of the Subpart W rules as proposed and should consider 

alternative approaches to these sources. The proposed rule requires the following parameters for 

onshore production storage tanks:

• Separator oil composition;

• Separator temperature;

• Separator pressure;

• Sales oil API gravity;

• Sales oil production rate;

• Sales oil reid vapor pressure;

• Ambient air temperature; and
Page | 25

• Ambient air pressure.

Current sampling practices are not detailed enough to support modeling input requirements. 

Industry standard practice only collects basic compositional information and production 

measurements for liquids, while E&P Tanks requires full speciation data from an extended 

laboratory analysis. This liquid analysis is expensive and often the sample is difficult to collect 

since it requires gathering a sample at the separator pressure. For some separators, the hardware 

is not in place to collect a pressurized sample. In addition, specific safety precautions must be 

employed to gather the liquid sample.

It is El Paso’s interpretation that engineering estimates can be used for the required operational 

parameters, since the rule does not specify metering and monitoring for these parameters. El

Paso requests confirmation of this interpretation. In addition, El Paso requests that tanks with a 

throughput of less than 5 barrels/day be excluded from reporting under Subpart W or be 

permitted to apply a default emission factor from the API Compendium in place of conducting 

modeling using process simulations.

XIV. § 98.233(o) Centrifugal compressor wet seal degassing vents 

Section 98.233(o) does not currently prescribe that wet seal vents be surveyed in each of the 

operational modes that occur during a reporting period (as does for reciprocating compressor 

vents). But the TSD17 does acknowledge these emissions differ in various operating modes. 

Therefore, it is not clear if it was the EPA’s intent to have the three mode requirement apply to 

centrifugal compressors. El Paso requests clarification on the requirement to survey in various 

modes of operation. (Note that because centrifugal compressors with wet seals cannot remain 

pressurized when offline, only two modes of operation are possible: operating and not operating, 

depressurized.) If this requirement was intended to apply, El Paso recommends that centrifugal 

compressors with wet seals be surveyed as per the “As Found” approach described under Section 

XV and that emission factors be calculated as presented in Table 7 below. 

Table 7 presents a sample calculation of the annual leak rate from a wet seal centrifugal 

compressor unit that is blown down when off line. In this example, hypothetical emission 

factors are used to represent the key sources. This example also assumes that the compressor 

unit in question has one compressor wet seal, one blow down valve, one pressure relief valve, 

and one pair of unit isolation valves. Finally, the compressor unit is assumed to be “Operating” 

75% of the year (6570 hours) and “Not Operating, Depressurized” the remaining 25% of the year 

(2190 hours). 

Therefore, as shown in Table 7, to calculate the contribution of wet seal leakage while the 

compressor unit is operating, the hypothetical emission factor for “Operating” wet seals (120.0 

scfh CH4) is multiplied by the number of wet seals (1) and again multiplied by the activity factor 

(6570 hours per year that the compressor is in “Operating” mode). This result was then divided 

by 1000 to convert to Mcf/yr (Mcf = 1000 cubic feet in US natural gas industry terminology) 

resulting in 788 Mcf CH4/year. Similar calculations are made for each of the other component 

 17 See Appendix M of the Greenhouse Gas Emissions Reporting from the Petroleum and Natural Gas Industry, Background 

Technical Support Document, page 160. 
Page | 26

categories, with the results from each category being totaled to calculate the overall annual 

compressor unit leak rate.

Note that in practice, emissions will be calculated by using a combination of unit specific 

measurement data and operating company emission factors. Actual measurement data will be 

used for each unit as available, and the emission factors will be used to project leakage from the 

mode which was not measured. This will make the calculations more facility specific. 

Table 7: Sample Calculation of Emissions from a Centrifugal Compressor Unit With Wet (Oil) 

Seal (Basis: 75% Utilization)

Component

Component 

Emission Factor

(scfh CH4)

No. of

Components

Activity Factor

(Hours Leaking/Yr)

Annual 

Emissions

(Mcf 

CH4/Yr)

Compressor Status: Operating

Wet (Oil) Seal – Operating 120 1 6570 Hours (Operating) 788

Pressure Relief Valve 102.6 1 6570 Hours (Operating) 674

Blow Down Valve 10.1 1 6570 Hours (Operating) 66

Compressor Status: Not Operating, Depressurized

Unit Isolation Valve Pair 1100 1

2190 Hours (Blown 

Down) 2409

Total Annual Emissions 

(Mcf CH4/year) 3938
Page | 27

XV. § 98.233(p) Reciprocating compressor rod packing venting: El Paso recommends 

monitoring in “As Found” mode. (Note: This section also applies to other vents as well).

Section 98.233(p) requires that all compressor vents be surveyed in each of the operational 

modes that occur during a reporting period:

1. Operating 

2. Standby pressurized 

3. Not operating, depressurized 

El Paso recognizes and mentioned in its’ comments18 to the EPA proposed reporting rule last 

year, that the operating mode of compressor units impacts leakage from key compressor 

components such as rod packing seals, blow down valves, and unit isolation valves. However, a 

survey of all three modes as required by the EPA in the Subpart W proposal creates enormous 

challenges and will result in greenhouse gas emissions (GHG) that otherwise, would not have 

occurred under normal operations.

To alleviate these problems, as the first step, the EPA should take into account that compressor 

units will primarily fall under one of the following operating scenarios: 

Mode 1 Mode 2

Scenario 1 Operating Standby pressurized

Scenario 2 Operating Not operating, depressurized

The proposed monitoring requirements do not consider challenges associated with atypical 

modes of operation. Currently, Subpart W does not take into account that the following modes 

of operation are considered atypical and probably occur less than 7% of the time (see Appendix 

I): 

1. Scenario 1 - For units that are normally blown down when off line, only a very short 

amount of time is spent in the “standby, pressurized” mode prior to being blown down 

(“not operating, depressurized” mode).

2. Scenario 2 - Units that are normally in the “standby, pressurized” mode when off line will 

only be depressurized for maintenance or during emergency conditions.

Additionally, it does not consider that requiring measurement of both typical and atypical modes 

of operation would result in unintended GHG emissions from unit blowdowns, disruption of 

operations and supply, and non-representative conditions. Furthermore, monitoring compressor 

units in atypical modes has the additional challenge of tracking the operating time in these 

modes, which is not a common practice by most companies today, and would be a major 

undertaking not justified by the level of improvement in capturing emissions. The increase in 

GHG emissions, difficulty in obtaining representative sampling, and supply disruption problems 

due to the three-mode sampling requirement are important aspects of the problem, which EPA 

appears not to have considered in proposing the three-mode requirement. EPA should consider 

the alternatives El Paso suggests below to help alleviate these problems. 

 18 Docket ID No EPA–HQ–OAR–2008–0508
Page | 28

To achieve the EPA’s goal of collecting meaningful and representative emissions data, the 

abovementioned operating scenarios should be the focal point of the EPA’s monitoring proposal

while considering the “as found” mode of operation of a given unit. The “as found” mode of a 

compressor is the mode in which it is operating on the day of a survey. Although El Paso 

compressor data shows that the “as found” approach will result in a large sample size of all 

modes19 that can be related to the annual emissions from the facility, El Paso recommends a 

hybrid monitoring approach to ensure an ample data set of all modes over a reasonable amount 

of time:

1. Each unit located at an applicable facility shall be surveyed once a year in the “as found” 

mode; and

2. A minimum of 33% of the total population of units that spend more than 10%20 of their 

time in “not operating, depressurized” mode, shall be surveyed in that mode once every 3 

years21. The “not operating, depressurized” mode shall be based on the operation of the 

unit during the year prior to the 3 year period. 

Note that the 3 year time period referenced above will not preclude the submission of emissions 

data in the “not operating, depressurized” mode during the first reporting year as discussed in the 

appendix.

Again, it is anticipated that the “as found” approach will result in a large sample size of all 

modes. However, for any given unit it would be acceptable if it were surveyed in its “as found” 

mode all three times during the three year period. 

In practice, each compressor unit would be surveyed in the mode in which it was found when the 

survey took place. This data would then be used to calculate emissions factors for each key 

component category in each mode. Total unit emissions would then be calculated as follows:

1. For the mode in which the unit was surveyed (“as found”), the emissions will be based on 

actual measurements. 

2. For the other mode, the emissions will be based on the number of key components, and 

emission factors developed for this mode based on company-wide sampling results in this 

mode. 

3. The “atypical” mode will be rolled up with one of the typical modes as described in 

Equation 4a or 4b in Appendix I.

 19 Over the past three years (2007 – 2009), compressor units in the El Paso transmission system spent over 50% of their time 

in each of the modes as follows: Operating (28.6%), Standby, Pressurized (34.7%), and Not Operating, Depressurized 

(36.8%). Consequently, “As Found” sampling should provide a representative sample of each mode. 20 The basis for including only units that are in the "not operating, depressurized" mode over 10% of the time is that 

emissions from this mode will no longer be dominant at this point. Based on EPA's estimates from the Lessons Learned 

document in the TSD, the "not operating, depressurized" mode might emit on average 2.7 times more than the "Operating" 

mode for a unit with four compressor seals. If this is true, for units that are depressurized less than 10% of the time, the 

depressurized mode contributes less than 25% of the total emissions. 21 The three year window is required because it will not be possible to bring many units offline until their normal 

maintenance cycle arises. 
Page | 29

Details regarding the development of emission factors, including sample calculations, are 

presented in Appendix I. The methodology is illustrated in the table below.

Total population of units located at applicable facilities 1000

Number of units that operated 10% in "not operating, depressurized" 

mode during the year prior to 3 yr period 400

Min. number of units that must be surveyed in "not operating,

depressurized" mode every year, over 3 yr period 133

Lastly, clarification is needed between Section 98.233(p)(2)(i) which requires the measurement 

of compressor blow down vents along with other compressor unit vents and Section 

98.233(q)(3) which indicates that compressor blow down vents should be surveyed using an IR 

camera and then the “leaker” emission factor applied to calculate leakage.

XVI. § 98.233(q) Leak detection and leaker emission factors

Currently, Section 98.233(q) requires surveying standard components (such as connectors and 

valves, as opposed to vented components) with an IR camera and then applying a “leaker” 

emission factor to the number of leaks found for each component type. It’s clear that EPA’s 

intent was to reduce labor costs in this area. However, this approach still requires a substantial 

amount of effort that does not provide a large improvement in the accuracy of the reported 

emissions. It would also distract from collecting accurate data from the vented components that 

make up the majority of non-combustion emissions. 

The contribution of leakage from standard components averages about 20% of the total leakage 

at transmission compressor stations (Howard et al., 1999 – this was a joint study sponsored by 

PRCI, GRI, and EPA) 22. Because the proposed method uses an emission factor as opposed to a 

measurement, there will still be uncertainty in this method. The EPA Natural Gas Star program 

has previously developed emission factors for compressor stations based on the number of 

compressor units at the site (EPA, 2000)23. These factors include both standard and vented 

components but could easily be recalculated to assess only standard components. 

Although the proposed method of using leak detection combined with leaker emission factors 

would be expected to give better results than applying a facility emission factor, this 

improvement only applies to approximately 20% of the total facility leak rate. Consequently, the 

improvement in the reporting accuracy for the entire facility is probably less than 5%, while the 

effort involved might require as much as 50% of the total leak survey effort.

 22 Howard, T., R. Kantamaneni, and G. Jones, 1999. Cost Effective Leak Mitigation at Natural Gas Transmission 

Compressor Stations. PR-246-9526. PRCI, 1515 Wilson Boulevard, Arlington, VA22209.

23 EPA, 2000. Natural Gas STAR Default Value Analysis Project. 7th Annual Natural Gas STAR Implementation 

Workshop, October, 2000. 
Page | 30

Allowing a facility emission factor for standard components as an option to leak screening lets 

facilities focus on making measurements at the vented components that account for 80% of the 

total emissions. This full focus should improve the accuracy of the data collected from these key 

sources. 

Should EPA still feel that leak surveys of standard components are essential, it would be better to 

allow more options than just the IR camera to conduct these surveys. Although these cameras 

are useful tools, screening with flame ionization detectors, catalytic oxidation/thermal 

conductivity detectors, and soap solutions have been proven to be effective (Howard et al., 1999; 

EPA, 2002; KSU, 2006) and should not be excluded. 

It’s possible that EPA felt that the IR cameras would be the most cost effective approach, and for 

some companies, that may be true. However, other companies might want to have in-house 

personnel conduct leak screening with techniques that they already know how to use. 

Clearstone’s 2006 study (KSU, 2006)24 notes that a 2 person crew with an IR camera can survey 

approximately 6,400 components per day. The PRCI study (p. A-1-14) found that experienced 

personnel could survey transmission station components using a combination of soap and 

catalytic oxidation/thermal conductivity detectors at a rate of 350 components per person per 

hour, or 5,600 components per two person crew per eight hour day. During this time study, the 

personnel found 99.6% of combined leaks found by using this method and a Foxboro TVA –

1,000, so these methods are clearly still effective.

Facilities that have access to IR cameras and trained personnel could apply the IR camera if they 

so desired. Other facilities without these resources could rely on past experience and conduct the 

leak screening on a flexible time schedule without necessarily acquiring more equipment or 

hiring contractors. 

Contribution of Standard Components to Total Leakage

There may be an overemphasis on the importance of standard components at facilities due to 

Clearstone Engineering’s studies at gas plants in 2002 and 2006. Although these studies were 

detailed and well executed, gas processing plants have a much larger ratio of standard 

components per compressor unit than is found at transmission compressor stations. For instance, 

in the PRCI study done at thirteen transmission compressor stations, the number of components 

per compressor unit was a little over 400. The Clearstone studies don’t list a complete inventory 

of compressor units, but if there were twenty units at each site, the ratio of components to 

compressor units would be approximately 1,000, about two and one half times greater than at 

transmission sites. Additionally, standard components at processing plants may be subjected to 

greater heat and vibration in some areas than at transmission compressor stations.

 24 National Gas Machinery Laboratory, Kansas State University; Clearstone Engineering, Ltd; Innovative 

Environmental Solutions, Inc., 2006. Cost-Effective Directed Inspection and Maintenance Control Opportunities at 

Five Gas Processing Plants and Upstream Gathering Compressor Stations and Well Sites. For EPA Natural Gas 

STAR Program. March 2006. 
Page | 31

The 2002 Clearstone study (EPA, 2002)25 indicated that connectors and valves accounted for 

over 50% of the total leakage (Figure 10 of that study), whereas at transmission stations that 

number is more likely to be 20% (Howard et al, 1999). Additionally, the 2006 Clearstone study 

(KSU, 2006) indicates that connectors and valves were down to approximately 32% (Figure 13

of that study). Open ended lines contributed another 30%, but this category apparently includes 

compressor blow down valve leakage which would probably dominate the leakage.

It is understood that for the purposes of the proposed rule that different leaker emission factors 

have been developed for transmission as opposed to processing. However, the key point is that 

standard components in transmission don’t contribute to the total leakage as much as the 

Clearstone studies might be interpreted to suggest.

XVII. § 98.233(q)(2) Leak detection and leaker emission factors for Onshore natural gas 

processing facilities

Currently, Section 98.233(q) requires surveying centrifugal compressor dry seals (for units 

operated at processing facilities) with an IR camera. Given the fact that dry seals are designed to 

emit in small amounts under normal operating conditions, it seems more reasonable to apply a 

population count and population emission factor to this component rather than require leak 

detection. Therefore, El Paso recommends that requirements for dry seal components fall under 

Section 98.233(r). 

XVIII. § 98.233(q)(3) Leak detection and leaker emission factors for Onshore natural gas 

transmission compression facilities 

Table W-3 referenced under Section 98.233(q)(3) does not include a centrifugal compressor 

component leaker factor for dry seals. Given this component was also excluded from the 

transmission segment emission source list under Section 98.232(e) it is El Paso’s interpretation 

that the transmission segment does not have any monitoring requirements for centrifugal 

compressor dry seals. El Paso requests confirmation of this interpretation. 

If it was the EPA’s original intent for this component to be included in the rule, El Paso 

recommends the monitoring requirements be similar to those prescribed for processing facilities, 

and that a population emission factor be added to Table W-3 for dry seals on centrifugal 

compressor units operated at transmission compression facilities. 

XIX. § 98.233(r) Population count and emission factors

El Paso does not track all fugitive component counts for its pipeline and onshore oil and gas 

production operations. In evaluating the impact of the proposed rule requirements, El Paso 

estimates that it would have to locate and log over 1 million fugitive components across 

operations in ten states. Given the sheer number and geographic dispersion of fugitive 

 25 EPA, 2002. Identification and Evaluation of Opportunities to Reduce Methane Losses at Four Gas Processing 

Plants. Clearstone Engineering Ltd. June 20, 2002. <www.epa.gov/gasstar/documents/four_plants.pdf> 
Page | 32

components associated with onshore oil and gas operations alone, it is not possible to definitively 

account for all components, nor is it possible for EPA to verify the accuracy of the reported 

component counts for all operators. El Paso strongly encourages EPA to consider the trade off in 

emission accuracy between the use of component level emission factors applied to a count of 

components with a high degree of uncertainty due to the vast number of sources versus a slightly 

less accurate equipment level emission factor applied to a count of equipment that is known to a 

high degree of certainty. Furthermore this approach is more easily verified by EPA as well as 

the operators.

Given the geographic dispersion and number of small fugitive components, in addition to the 

disproportionate cost relative to the quantity of emissions, the rule should provide equipment 

level “population-based” counts and emission factors from industry accepted protocols such as 

the API Compendium, INGAA guidelines, etc. to quantify “population-based” fugitive 

emissions. 

EPA states in the Preamble that the purpose of the Mandatory Reporting Rule is to guide policy 

development for future permitting and compliance purposes. General equipment-level emission 

counts are acceptable for this purpose, and therefore should be acceptable for petroleum and 

natural gas systems. 

XX. § 98.233(u)(2)(iv) GHG Volumetric emissions for underground natural gas storage 

facilities 

The proposed rule requires that GHG volumetric emissions be calculated at standard conditions 

using the natural gas volumetric emissions at standard conditions (Es,n) and mole percent of GHG 

in the natural gas (Mi). For underground natural gas storage facilities, Mishall be the annual 

average mole percent in the natural gas stored underground. However, “natural gas stored” 

typically includes base gas and newly injected gas. Gas composition may not be readily 

available for base gas in older storage facilities and the composition of the injected gas will only 

be known for each injection cycle. Fugitive emissions for storage stations will occur from 

sources located between the suction header and storage wells, El Paso recommends the gas that 

passes through the facility be allowed as the basis of the GHG mole percent for underground 

natural gas storage facilities.

XXI. § 98.233(x) Hydrocarbon liquids dissolved CO2

The proposed rule requires determining the amount of CO2 retained in hydrocarbon liquids and 

produced water after flashing in tanks. The rule requires collecting these samples once each 

quarter for every produced water or hydrocarbon tank. 

This source has the highest cost per metric tons of emissions based on El Paso’s cost estimates. 

El Paso urges EPA to limit the applicability of the requirements for dissolved CO2 specifically to 

onshore oil and gas operations that utilize high CO2 content streams for enhanced oil production. 

This is the only operation for which this emission source makes sense and this is clearly the 

intent for this emission sources as discussed in the TSD. The rule language should make this 

distinction and only be applicable to EOR operations. 
Page | 33

XXII. § 98.235 Procedures for estimating missing data

The proposed missing data substitution requirements for Subpart W differ from the requirements 

for Subparts C. 

The proposed requirements for Subpart W are “If data are lost or an error occurs during annual 

emissions estimation or measurements, you must repeat the estimation or measurement activity 

for those sources as soon as possible, including in the subsequent reporting year until valid data 

for reporting is obtained. Data developed and/or collected in a subsequent reporting year to 

substitute for missing data cannot be used for the subsequent year’s emission estimation.”

For Subpart C, 98.35(a)(1) requires substituting “the arithmetic average of the quality-assured 

values of that parameter immediately preceding and immediately following the missing data 

incident. If the ‘‘after’’ value has not been obtained by the time that the GHG emissions report is 

due, you may use the ‘‘before’’ value for missing data substitution or the best available estimate 

of the parameter, based on all available process data (e.g., electrical load, steam production, 

operating hours). If, for a particular parameter, no quality-assured data are available prior to the 

missing data incident, the substitute data value shall be the first quality-assured value obtained 

after the missing data period.” The requirements for Subpart Y are similar to Subpart C.

For consistency, El Paso recommends using similar requirements for missing data under Subpart 

W rather than introducing a different set of requirements.

XXIII. § 98.236(c) Data reporting requirements

El Paso has been voluntarily quantifying and reporting its greenhouse gas emissions since 2006 

and was the first natural gas company to certify its emissions inventory under the California 

Climate Action Registry (CCAR). Industry standard practices for compiling GHG inventories 

for natural gas operations rely on available operational data, engineering estimates, and counts of 

major equipment. It is not standard industry practice to account for every fugitive component, to 

maintain manufacturer information for every pneumatic device, to meter flow rates for all vented 

and flared streams, or to analyze pressurized compositions or dissolved CO2 from all produced 

liquids. 

Furthermore, there seems to be multiple items required to be reported that are not relevant to the 

emission estimates but will increase the compliance burden and cost for the reporters. Therefore, 

El Paso suggests eliminating certain reporting requirements as explained below.

1. For tank emissions identified using optical gas imaging instrument

Per Section 98.236(c)(11), the requirement is to report the following:

(i) Immediate upstream separator temperature and pressure.

(ii) Sales oil API gravity.

(iii) Tank capacity in barrels.

(iv) Tank throughput in barrels.

The above items have no relevance to the emission estimations since these emissions will be 

directly measured. This information cannot be used to derive emission factors as the emissions 
Page | 34

do not depend on the above. The API gravity determination may incur additional cost for the 

reporters if this item is not readily available.

2. Compressor throughput

The proposed rule requires reporting of the total throughput for centrifugal compressors with wet 

seal degassing vents and reciprocating compressor rod packing report pursuant to Sections

98.236(c)(17)(iii) and (18)(i), respectively. Again, this will increase the reporting burden as the 

environmental systems usually do not contain this information and new process will have to be 

established to make this information available for emission reporting. This will also significantly 

increase the scope of information subject to certification by the Designated Representative.

3. Compressor Component Counts 

Section 98.236(c)(19)(i) requires a component count for each fugitive emissions source. It’s not 

quite clear if this means a full component count of all components in natural gas service, or a list 

of all leaking components. If a full component count is intended, this adds a substantial amount 

of work to the surveys. A half-day visit to a facility or reporting area to perform a survey(s) 

could increase to a 3 day visit (or more), and thus will have significant impact on scheduling and 

cost. Since the proposed method is based on leaking component count and leaker emission 

factors, full component counts do provide any information relevant to emission estimates. 

Elimination of this requirement will allow more focus on accurate data collection and reporting. 

4. Facility throughput

Minimum and average throughput for each operation listed in paragraphs (a)(1) through (a)(8), 

i.e., each facility subject to reporting, is required to be reported per 98.236(d). This information 

is not relevant to the emission estimations and significantly increases the reporting burden and 

adds to the certification burden.

XXIV. § 98.238 Definitions 

Onshore petroleum and natural gas production facility

Consistent with our comments under Section II, we recommend the use of “facility” be replaced 

with “reporting area” as follows: 

Onshore petroleum and natural gas production facility reporting area means all 

petroleum or natural gas equipment associated with all petroleum or natural gas 

production wells under common ownership or common control by an onshore petroleum 

and natural gas production owner or operator located in a single hydrocarbon basin as 

defined by the American Association of Petroleum Geologists which is assigned a three 

digit Geologic Province Code. Where an operating entity holds more than one permit in 

a basin, then all onshore petroleum and natural gas production equipment relating to all 

permits in their name in the basin is one onshore petroleum and natural gas production 

facility reporting area.

XXV. § 98.6 Definitions

Flare combustion
Page | 35

The definition of flare combustion is poorly worded. We suggest the following:

Flare combustion emissions means emissions of CO2 and N2O formed during the 

combustion process and emissions of CH4 resulting from the incomplete combustion of 

gas in flares.

Onshore petroleum and natural gas production owner or operator

The proposed definition on page 18635 has an incorrect reference to 98.230(b)(2). The correct 

reference is 98.230(a)(2). 

XXVI. Preamble Section I.(C.) on Page 18610 — Legal Authority 

EPA states in the Federal Register notice for the proposed rule that it is proposing the rule “under 

its existing CAA authority,” specifically, Section 114(a)(1) of the CAA. 75 Fed. Reg. 18608, 

18610-11 (Apr. 12, 2010). As EPA notes in the administrative record for the MRR rule it 

finalized last year, however, and as it states again in the current proposal, EPA faced a choice of 

proceeding under Section 114 or under the Consolidated Appropriations Act. Id. at 18610. As 

EPA recognized in last year’s administrative record, however, “[b]y proceeding using the 

authority of the Appropriations Act, rather than the Clean Air Act, EPA would be limiting the 

scope and time period that the program would be effective, consistent with the appropriations 

law that made available the funds to create this program.” (See Doc. No. EPA-HQ-OAR-2008-

0508-0056.2.) Possibly in an effort to justify monitoring as well as reporting requirements and 

to avoid limitations on the duration of the program, EPA chose to rely on Section 114 of the 

CAA. 

By relying on Section 114 as authority for the proposed rule, EPA exceeded its statutory 

authority under the Clean Air Act. EPA’s only authority for the proposed rule is under the 

Consolidated Appropriations Act. That authority is limited in scope to reporting requirements, 

not monitoring requirements, and is limited in duration to the fiscal year for which the funds are 

appropriated. Legal authority for this position is provided in Appendix III to these comments, 

which is incorporated by reference as if fully set out herein. 

In addition, or in the alternative, to being in excess of EPA’s statutory authority, Subpart W, if 

finalized as proposed, fails to meet the standard of reasonableness applicable to governmental 

requests for information. Section 114 is the same section that authorizes EPA to issue 

administrative subpoenas to individual companies to collect information (also known as Section 

114 requests). To be valid under Article 4 of the Constitution, subpoenas must be reasonable, 

relevant to the purpose, not overly broad or unreasonably disruptive, and not unreasonably

burdensome, and the recipient is entitled to a finding as to whether EPA must pay the costs for 

responding to a burdensome subpoena. Bunker Hill, 728 F. Supp. 629 (quoting See v. Seattle, 

387 U.S. 541, 87 S.Ct. 11737, 1740 (1967)); U.S. v. Tivian Lab, 589 F.2d 49, 55 (1st Cir. 1978); 

In Re Bunker Hill Mining and Smelting Company, 728 F. Supp. 626, 629 (D. Idaho 1990). We 

believe Section 114 as proposed attempts to promulgate by rule an ongoing monitoring and 

reporting requirement that would be disallowed by the court as unreasonably burdensome if EPA 

were to try to impose it on industry by Section 114 requests on a company-by-company basis.
Page | 36

If finalized as proposed, and as discussed in more detail throughout these comments, the rule 

lacks a reasonable relationship between the purported statutory purpose of collecting data 

reasonably necessary to inform GHG policy and the detailed and onerous monitoring provisions 

it proposes to impose on oil and natural gas systems. In addition, the rule is not supported by 

sound reasoning; fails to give reasonable consideration to important aspects of the problem, 

including the effects and costs of the choices it proposes to make; and fails to consider 

substantial arguments and alternative solutions.

El Paso submits the comments on the proposed rule set out above subject to and without waiving 

its concerns regarding the legal aspects of the proposal expressed in this section.

Page | 38

ATTACHMENT 3

EL PASO’S LEADERSHIP CREDENTIALS

 El Paso is sponsoring the Ruby pipeline26 project to provide California and the West Coast 

with increased access to abundant Rocky Mountain natural gas. Ruby is the first major 

interstate pipeline to incorporate greenhouse gas (GHG) mitigation measures in its 

construction and design, with a goal of offsetting 100% of its carbon footprint. 

 El Paso has been a member of the California Climate Action Registry (CCAR) since 2006

and has been reporting its GHG emissions since 2007. In August 2008, El Paso became the 

first company to file an emissions inventory covering all applicable GHGs, including 

methane, N2O and CO2 for its US operations. In addition, on December 31, 2007, El Paso 

reported its 2006 GHG emission estimates under DOE 1605(b) requirements. 

 El Paso is a member of The Climate Registry’s (TCR) Advisory Committee.27 As such, El 

Paso provides input on technical elements associated with TCR’s design and 

implementation, and feedback on broader policy issues that could affect the organization’s 

support of state and provincial climate programs.

 El Paso has participated and reported on GHG related programs into the Carbon Disclosure 

Project (CDP). In June 2008, El Paso released its first Corporate Sustainability Report 

(CSR) report28.

 Since 1993, the El Paso Pipeline Group’s GHG emission reductions from participation in 

the EPA Natural Gas Star Program totals over 55 billion cubic feet of natural gas, or 

approximately 20 million tons of CO2e. These and many other internal initiatives within El 

Paso have resulted in El Paso Pipeline Group achieving a lost and unaccounted for (LAUF) 

gas rate of less than 0.15% for 2006. In 2008, the El Paso Pipeline Group was voted the 

“Transmission Partner of the Year” for the second time.

 El Paso has implemented fugitive and vented methane leak measurement and research 

programs dating back to the 1990s. We have experience in practical applications of various 

tools such as the Infra-red camera, Hi-Flow Sampler etc. Part of data has been shared with 

the EPA as part of the Mandatory Reporting Rule making process.

 On May 20, 2009, El Paso joined a coalition of Corporate and Conservation Leaders to

release details of an agreement on policies aimed at protecting the world’s tropical forests. 

Under the agreement, companies would be eligible to receive credit for reducing climate 

pollution by financing conservation of tropical forests. The full agreement is available at 

http://www.adpartners.org. 

 26 http://www.rubypipeline.com/ 27 El Paso was nominated for this position by California Environmental Protection Agency 28 http://elpaso.com/CSR/index.html
Page | 39

 El Paso is part of the Coalition for Emission Reduction Projects (CERP), which aims to 

educate policy-makers about the key role that offsets can play in a U.S. cap-and-trade 

program. The CERP is a unique group, which brings together leading companies in the

energy, financial and offset provider sectors. 

 El Paso maintains leadership positions in the Interstate Natural Gas Association of America 

(INGAA) on GHG and in the development of the INGAA Greenhouse Gas Emissions 

Estimation Guideline for Natural Gas Transmission and Storage. 

 El Paso was recognized for its technical, regulatory and policy leadership on GHG issues 

by Southern Gas Association (SGA) and received SGA’s 2007 Environmental Stewardship 

Excellence Award.

 El Paso is part of the Dow Jones Sustainability World Index (DJSI World), an annual 

review of the sustainability efforts of the world’s leading companies. The index identifies 

the leading companies in 57 industries, according to corporate best practices in issues 

including corporate governance, stakeholder relations, energy consumption, and human 

resources development, as well as industry-specific criteria. Only the top 10 percent of the 

world’s largest 2,500 companies are included in the index. El Paso is listed in the oil and 

gas industry.

APPENDICES

Page | 1

APPENDIX I

Support Documentation for “As Found” Monitoring Proposal 

Monitoring Challenges

1. Surveying all three modes will require an additional blow down event per unit, because if a 

unit is on line it would have to be taken off line and then blown down to survey the depressurized 

mode. This would result in an additional blowdown event that would increase GHG emissions. 

On the other hand, if a unit were already blown down, it would have to be pressurized and put on 

line, and then after the measurements were made, it would be taken back off line and blown down. 

This would also increase GHG emissions. Hence, the monitoring requirement will result in 

increased greenhouse gas emissions that otherwise would not have occurred under normal 

operations as per the case shown below: 

At least 50% of compressor units in El Paso’s transmission system are currently 

depressurized when off line and as a result, already blown down. So all of these units 

would have to be pressurized and put on line to make a measurement before being put back 

off line and blow down a second time. All units found operating during the survey would 

have to be taken off line in order to measure either the “standby pressurized” mode and the 

“not operating – depressurized” mode. 

2. Putting a unit on line temporarily may not provide a representative measurement since the 

rod packings may not be properly warmed up or it may have to be placed in a re-circulating mode29

if there is no extra gas capacity in the pipeline.

3. It may not be feasible to take a unit off line due to pipeline demand – requiring a unit to 

come off line might disrupt gas supply and operations. This may be especially true in the 

production sector or at transmission stations with only centrifugal units where there may not be 

any additional units with which to switch.

4. Generally, companies in the oil and gas sector keep track only of the compressor operating 

hours, so that the only current reliable information is whether a compressor unit is operating or offline. It is El Paso’s understanding that there is no current standardized industry practice or method 

of determining whether an off-line compressor is pressurized or depressurized. Usually, standard 

operating procedures are employed to estimate the hours when the unit is off-line. If the standard 

procedure was to blow down the unit when off- line, then it would be assumed that all off-line 

hours were spent depressurized. Similarly, if the standard procedure was to leave the unit 

pressurized when off-line, it would be assumed that all off-line hours were pressurized. Modifying 

the compressor’s Remote Terminal Units (RTU’s) for all affected units to track hours in atypical

modes would be a major undertaking not justified by the level of improvement in capturing 

emissions.

 29 In a recirculating mode, the gas leaving the discharge side of the compressor flows through a bypass valve and into the 

suction side of the compressor. As a result, suction and discharge pressures are essentially equal in recirculating mode. 

During typical compressor operations, the difference between suction and discharge pressures are at least 200 psig.
Page | 2

5. Units that are usually depressurized when off line might spend a very short amount of time 

pressurized prior to being blown down, and units that are left pressurized while off line might be 

depressurized for short periods for maintenance. However, these are atypical conditions. For 

instance, in 2009, compressor units in El Paso’s transmission system that are typically left in 

“standby pressurized” mode when off-line were “operating” 31.6% of the time, in “standby 

pressurized mode 61.9% of the time, and “unavailable” 6.5% of the time. This “unavailable” 

designation comes from El Paso RTU data and the unit may or may not be depressurized during 

this time, so in the worst case the “not operating – depressurized” mode (the atypical mode for 

units typically left pressurized when off line) only occurs for 6.5% of the time. 

For units which are typically depressurized when off-line, detailed data on the amount of time 

spent in “standby pressurized” (the atypical condition) is not available. However, in most cases 

these units are only left in the “standby pressurized” for a short period (less than one hour) prior to 

being depressurized.

Effect of Operational Mode on Leakage

Although the mode of a compressor unit can substantially affect the leakage for individual units, 

the average differences may not be as great as indicated in the EPA source document mentioned in 

the technical support document for the proposed rule. This Star program “Lessons Learned” 

publication (EPA, 2004)

30 states that rod packings on idle units may leak at four times the rate of 

rod packings on running units. 

However, the primary references for this document are personal communications and better data is 

currently available. For instance, the original GRI survey of compressor stations (Indaco, 1995)31

found a 19% increase in idle versus running rod packings, while in the PRCI study (Howard et al., 

1999 – cosponsored by PRCI, GRI, and EPA), idle rod packings were found to leak on average at a 

46% greater rate than running rod packings. 

A more extensive data set has been compiled by El Paso. This data was primarily collected by 

outside contractors and has approximately ten times as many measurements as the PRCI data set. 

This data indicates an average of only 6% increase in leakage from seals in idle pressurized mode 

compared to seals in running mode. Consequently, the difference in leakage between running 

units and idle but pressurized units is probably not as significant as indicated in the EPA 

Lessons Learned source. 

For the depressurized units, the EPA Lessons Learned document suggests an average leak rate of 

23.3 scfm. This is in line with the original GRI study of 26.1 scfm. However, the PRCI study 

indicated a leak rate of 6.78 scfm (although this was based on a smaller data set than GRI it was a 

 30 EPA, 2004. Reducing Emissions when Taking Compressors Off-Line. EPA430-B-04-001, February 2004.

31 Indaco, 1995. Leak Rate Measurements at US Natural Gas Transmission Compressor Stations. GRI-94/0257.37. 

Gas Research Institute, 8600 West Bryn Mawr Avenue, Chicago, IL 60631.
Page | 3

more diverse set of stations). Finally, El Paso’s data set (which has over four times more data 

points for unit valves than the GRI study) indicates a leak rate of 9.21 ± 2.64 scfm.

To estimate the differences between modes, let’s assume a model of a reciprocating compressor 

unit that has one blow down valve, four compressor cylinders and therefore four rod packing seals, 

and one pair of unit isolation valves. When either running or in standby pressurized mode, there is 

potential leakage across the blow down valve and through the rod packings. When depressurized, 

the blow down valve is open and leakage measured from that vent is due to leakage across the unit 

isolation valves.

Table 1 summarizes the available emissions factors and the results of the model using the available 

data. 

Table 1: Emission Factors and Projected Leak Rates from Related Leak Studies

Component EPA

(EPA, 2004)

GRI 

(Indaco, 1995)

PRCI 

(Howard, 1999)

El Paso (1998 –

present)

Rod Packing – Running 0.3 1.02 ± 0.51 1.66 ± 0.48 1.96 ± 0.23

Rod Packing – Idle, Pressurized 1.3 1.21 ± 0.47 2.42 ± 1.05 2.08 ± 0.33

Blow Down Valve 7.5 2.53 ± 1.07 0.39 ± 0.33 2.50 ± 0.72

Unit Isolation Valve Pair 23.3 26.1 ± 9.41 6.78 9.21 ± 2.64

Total Unit Leakage1

 Unit Running 8.75 6.61 7.03 10.3

 Unit Idle – Pressurized 12.7 7.37 10.1 10.8

 Unit Depressurized 23.3 26.1 6.78 9.21

Ratio to Leakage from Running 

Units

 Unit Running 1.0 1.0 1.0 1.0

 Unit Idle – Pressurized 1.43 1.11 1.43 1.05

 Unit Depressurized 2.67 3.96 0.96 0.89

1 Assumes four rod packings, one blow down valve, and one pair of unit isolation valves

Based on these projections, we might expect idle/pressurized units to leak on average between 5% 

and 43% more than running units. Depressurized units might leak on average slightly less than 

running units to as much as four times greater.

The El Paso and PRCI data indicate there is little difference between operating modes on average, 

although for individual units there may be substantial differences. If this is the case, sampling 

units in an “As Found” mode should provide an excellent representation of total leakage.
Page | 4

Calculation of System-wide Emissions Using Emission Factors 

To aid in understanding the relative contributions of various leak sources to total emissions, a 

simple model of compressor station fugitive methane emissions can be constructed based on the 

major sources of leakage. This model is illustrated in Figures 1, 2, and 3. 

Figure 1 shows the leak sources for a unit in the “Operating” mode. In this mode leakage may 

occur through the rod packing seals and across the blow down valve and pressure relief valve, 

which are closed when the unit is operating. Much smaller leakage may also occur at standard 

components (such as connectors and valves) on the compressors themselves but this leakage is 

addressed by Section 98.233(q) of Subpart W. For this case, the total leakage from the key vented 

components while in the operating mode is calculated per Equation 1:

LROperating = (NCS-Operating x EFCS--Operating) + (NBDV x EFBDV)+ (NPRV x EFPRV) (Eq. 1)

where:

LR Operating = Leak rate from a compressor unit in “Operating” mode (scfh CH4)

NCS-Operating = Number of compressor seals on the “Operating” unit

EFCS—Operating = Emission factor for compressor seals on “Operating” compressors (scfh CH4/seal)

NBDV = Number of blow down valves on the “Operating” unit

EFBDV = Emission factor for blow down valves (scfh CH4/blow down valve)

NPRV = Number of pressure relief valves on the “Operating” unit

EFPRV = Emission factor for pressure relief valves (scfh CH4/pressure relief valve)

For most compressor units, the number of blow down and pressure relief valves will be one of 

each, but there are some units that have more. Additionally, the emission factors for both blow 

down valves and pressure relief valves are not expected to differ between units that are in the 

“Operating” mode and in the “Standby Pressurized” mode, i.e., these factors are not impacted by 

mode.

Figure 2 shows the leakage for a unit in the “Standby Pressurized” mode. The leakage in this 

mode occurs at the same sources as in the “Operating” mode except that the leakage through the 

rod packing seals may differ between the two and consequently is represented by a different 

emission factor. For this case, the total leakage from the key vented components while in the 

standby pressurized mode is calculated per Equation 2:

 LR Standby Pressurized = (NCS-Standby Pressurized x EFCS—Standby Pressurized) + (NBDV x EFBDV)+ (NPRV x EFPRV) (Eq. 2)

where:

LR Standby Pressurized = Leak rate from a compressor unit in “Standby Pressurized” mode

NCS-Standby Pressurized = Number of compressor seals on the “Standby Pressurized” unit

EFCS—Pressurized = Emission factor for compressor seals on “Standby Pressurized” compressors

NBDV = Number of blow down valves on the “Standby Pressurized” unit

EFBDV = Emission factor for blow down valves

NPRV = Number of pressure relief valves on the “Standby Pressurized” unit

 EFPRV = Emission factor for pressure relief valves.
Page | 5

Figure 3 represents the leakage from a reciprocating compressor unit that is in the “Not Operating 

– Depressurized” mode. When a unit is depressurized (blown down), the only source of leakage 

will be through the unit isolation valves, which are closed in order to isolate the unit from the main 

pipeline. Leakage through these valves travels through the open blow down valve and is measured 

at the blow down vent. The leakage in this case is calculated pursuant to Equation 3:

 LRNot Operating-- Depressurized = NUnit Isolation Valve Pairs x EF Unit Isolation Valve Pairs (Eq. 3)

where:

LRNot Operating-- Depressurized = Leak rate from a compressor unit in “Not Operating – Depressurized” mode

NUnit Isolation Valve Pairs = Number of unit isolation valve pairs

EF Unit Isolation Valve Pairs = Emission factor for unit isolation valve pairs.

The unit isolation valves are counted as a pair because there will always be at least one suction 

valve and one discharge valve and measurements at the blow down vent cannot distinguish which 

valve might be leaking. Typically there will be only one pair per unit at transmission compressor 

stations; however, storage facilities may have more than one pair per unit.

Annual leakage from a compressor unit can then be calculated using known activity data (amount 

of time it spends in two of the three modes – “Operating”, “Standby Pressurized”, “Not 

Operating—Depressurized”) and the leak rate in two of the three modes per Equation 4a or 4b:

LRAnnual = (αOperating × LROperating) + (αStandby Pressurized. × LRStandby Pressurized). (Eq. 4a) or 

LRAnnual = (αOperating × LROperating) + (αNot Operating--Depressurized × LRNot Operating—Depressurized) (Eq. 4b)

where:

LRAnnual = Annual leak rate from the compressor unit (scf)

αOperating = Amount of time compressor unit is “Operating”

αStandby Pressurized = Amount of time compressor unit is “Standby Pressurized”

αNot Operating--Depressurized = Amount of time compressor unit is “Not Operating—Depressurized”.
Page | 6

Figure 1: Leakage from Reciprocating Compressor Unit in “Operating” Mode

Standard Component Leakage

(Flanges, Fuel Fittings, Valve Caps)

Typically < 10% of Total and 

Addressed by Section 98.233 (q)

Pressure Relief Valve Leakage

Pressure Relief Valve 

Emission Factor

Blow Down Vent --

Leakage Across Closed 

Blow Down Valve 

Blow Down Valve Emission Factor

Compressor Seal Vent

“Operating” Emission Factor x 

Number of Compressor Seals

Reciprocating Compressor Unit – “Operating” Mode
Page | 7

Figure 2: Leakage from Reciprocating Compressor Units in “Standby Pressurized” Mode

Standard Component Leakage

(Flanges, Fuel Fittings, Valve Caps)

Typically < 10% of Total and Addressed by 

Section 98.233 (q)

Pressure Relief Valve Leakage

PRV Emission Factor x 

Number of PRV’s

Blow Down Vent --

Leakage Across Closed Blow Down Valve 

Blow Down Valve Emission Factor x 

Number of Blow Down Valves

Compressor Seal Vent

Standby/Pressurized Emission Factor 

x Number of Compressor Seals

Reciprocating Compressor Unit – “Standby Pressurized” Mode

Pressure Relief Valve Leakage

Zero When Unit Depressurized

Standard Component Leakage

(Flanges, Fuel Fittings, Valve Caps)

Zero When Unit Depressurized
Page | 8

Figure 3: Leakage from Reciprocating Compressor Units in “Not Operating--Depressurized” Mode

Unit Isolation Valves --

Leakage Across Closed

Unit Isolation Valves and Through 

Open Blow Down Valve 

Unit Isolation Valve Pair Emission Factor x 

Number of Isolation Valve Pairs

Compressor Seal Vent

Zero When Unit Depressurized

Reciprocating Compressor Unit – “Not Operating--Depressurized” Mode
Page | 9

Example Calculations of Leak Rates Using Emission Factors

Table 2 presents a sample calculation of the annual leak rate from a reciprocating compressor unit that is left 

pressurized when taken off line. In this example, hypothetical emission factors are used to represent the key 

sources. This example also assumes that the compressor unit in question has four compressor rod packing seals, 

one blow down valve, one pressure relief valve, and one pair of unit isolation valves. Finally, the compressor 

unit is assumed to be “Operating” 75% of the year (6570 hours) and “Not Operating—Depressurized” the 

remaining 25% of the year (2190 hours). 

Therefore, as shown in Table 2, to calculate the contribution of rod packing seal leakage while the compressor 

unit is operating, the hypothetical emission factor for “Operating” rod packing seals (99.0 scfh CH4) is 

multiplied by the number of rod packing seals (4) and again multiplied by the activity factor (6570 hours per 

year that the compressor is in “Operating” mode). This result was then divided by 1000 to convert to Mcf/yr 

(Mcf = 1000 cubic feet in US natural gas industry terminology) resulting in 2602 Mcf CH4/year. Similar 

calculations are made for each of the other component categories, with the results from each category being 

totaled to calculate the overall annual compressor unit leak rate.

Note that in practice, emissions will be calculated by using a combination of unit specific measurement data and 

operating company emission factors. Actual measurement data will be used for each unit as available, and the 

emission factors will be used to project leakage from the mode which was not measured. This will make the 

calculations more facility specific. 

Table 3 presents a similar example for a reciprocating unit that is depressurized when off-line.
Page | 10

Table 2: Sample Calculation of Emissions from a Reciprocating Compressor Unit --Pressurized When Not Operating

 (Basis: 75% Utilization) 

Component

Component Emission 

Factor

(scfh CH4)

No. of

Components

Activity Factor

(Hours Leaking/Yr)

Annual 

Emissions

(Mcf CH4/Yr)

Compressor Status: Operating

Rod Packing Seal – Operating 99.0 4 6570 Hours (Operating) 2602

Blow Down Valve 102.6 1 6570 Hours (Operating) 674

Pressure Relief Valve 10.1 1 6570 Hours (Operating) 66

Compressor Status: Standby Pressurized

Rod Packing Seal – Standby Pressurized 144.6 4 2190 Hours (Standby Pressurized) 1267

Blow Down Valve 102.6 1 2190 Hours (Standby Pressurized) 225

Pressure Relief Valve 10.1 1 2190 Hours (Standby Pressurized) 22

Total Annual Emissions (Mcf CH4/year) 4856
Page | 11

Table 3: Sample Calculation of Emissions from a Reciprocating Compressor Unit that is Depressurized When Not Operating

 (Basis: 75% Utilization)

Component

Component Emission 

Factor

(scfh CH4)

No. of

Components

Activity Factor

(Hours Leaking/Yr)

Annual Emissions

(Mcf CH4/Yr)

Compressor Status: Operating

Rod Packing Seal – Operating 99.0 4 6570 Hours (Operating) 2602

Blow Down Valve 102.6 1 6570 Hours (Operating) 674

Pressure Relief Valve 10.1 1 6570 Hours (Operating) 66

Compressor Status: Not Operating--Depressurized

Unit Isolation Valve Pair 1344 1 2190 Hours (Depressurized) 2943

Total Annual Emissions (Mcf CH4/year) 6286
Page | 12

Development of Emission Factors

To develop emission factors, each key compressor component (blow down valve vent, rod packing vent, and 

unit isolation valve pair) would be measured in the operating condition found at the time of the measurement. 

Time dependant population emission factors would be calculated for the mode in which each component was 

not surveyed, by averaging the leakage found in each component category over the total number of components 

surveyed in that year. In addition to the average leak rate (which is the population emission factor), the 

standard deviation, and the minimum and maximum observed leak rates should be reported for each factor per

component category. 

The following are the suggested categories for emission factors and are summarized in Table 4:

1) Blow Down Valve Vent (combine “Operating” and “Standby Pressurized” modes)

2) Pressure Relief Valve Vent (combine “Operating” and “Standby Pressurized” modes)

3) Rod Packing Seal Vent(s) on Reciprocating Compressors

a. “Operating” Mode

b. “Standby Pressurized” Mode

4) Unit Isolation Valve Pairs – “Not Operating” mode only

Table 4: Summary of Emission Factor Categories for Compressor Units

Component Operating Mode

“Operating” “Standby Pressurized” “Not Operating—

Depressurized”

Blow Down Valve Use measurements in either mode to develop combined factor Not Applicable

Pressure Relief Valves Use measurements in either mode to develop combined factor Not Applicable

Rod Packing Seals Individual Factor Individual Factor Not Applicable

Unit Isolation Valve Pairs Not Applicable Not Applicable Individual Factor

Although emission factors could be calculated by grouping data by units, facilities, operating companies, or 

industry, El Paso recommends grouping data at the operating company level. Grouping data by facility would 

most likely result in too few data points to be statistically valid, while grouping data industry wide would 

increase the uncertainty due to wider differences in equipment and operating practices.
Page | 13

APPENDIX II

Analysis of the EPA Proposed Greenhouse Gas Mandatory

Reporting Rule Cost Impacts for Natural Gas Systems

El Paso reviewed the EPA economic impact analysis for five types of natural gas industry facilities affected by 

Subpart W of the proposed GHG mandatory reporting rule: (1) onshore production facilities; (2) natural gas 

transmission facilities; (3) natural gas processing plants; (4) underground storage facilities; and (5) LNG import 

facilities. The information made available to the public through the rule docket is inadequate for conducting an 

independent review of EPA’s calculations and many of its assumptions that form the basis for the Subpart W 

cost estimates given in the RIA for onshore production facilities. Nonetheless, El Paso’s reviews indicates the 

first year average cost impact1 of $18,000 per pipeline transportation of natural gas system facility and $24,000 

per E&P facility is underestimated as shown in the following tables. 

Table A-1: Total Cost Comparison By Segment

 1 EPA Economic Impact Analysis for the Mandatory Reporting of Greenhouse Gas Emissions Under Subpart W Supplemental Rule (GHG 

Reporting), Final Report, December 8, 2009.

Yr 1 Total Yr 2 Total Yr 1 Total Yr 2 Total Yr 1 Total Yr 2 Total 

Onshore Production (Field >10K) $44,367 $13,691 $144,898 $111,401 69.38% 87.71%

Gas Processing $12,019 $5,530 $27,758 $22,324 56.70% 75.23%

Transmission $8,427 $4,825 $17,299 $16,853 51.29% 71.37%

Natural Gas Storage $11,913 $5,096 $15,320 $14,874 22.24% 65.74%

Yr 1 Total Yr 2 Total Yr 1 Total Yr 2 Total Yr 1 Total Yr 2 Total 

Onshore Production (Field >25K) $44,367 $13,637 $205,651 $160,106 78.43% 91.48%

Gas Processing $52,105 $11,607 $46,745 $43,155 -11.47% 73.10%

Transmission $17,081 $8,490 $27,078 $28,342 36.92% 70.04%

Natural Gas Storage $20,528 $9,153 $24,509 $25,773 16.24% 64.49%

LNG Import $21,251 $8,921 $20,354 $17,783 -4.41% 49.84%

Yr 1 Total Yr 2 Total Yr 1 Total Yr 2 Total Yr 1 Total Yr 2 Total 

Onshore Production (Basin >25K) $44,367 $13,637 $732,713 $546,810 93.94% 97.51%

Gas Processing $58,966 $13,795 $57,595 $48,870 -2.38% 71.77%

Transmission $21,910 $10,335 $33,081 $29,009 33.77% 64.37%

Natural Gas Storage $28,666 $13,572 $30,222 $26,455 5.15% 48.70%

Segment

Large

Segment

Small

Segment

Medium

EPA Estimates Independent Estimates Difference
Page | 14

Table A-2: Onshore Production Year 1 Compliance Costs Based on Independent Estimates

 Year 1 Labor 

Costs 

 Year 1 

Capital Costs Year 1 FTEs

 Year 1 Labor 

Costs 

 Year 1 Capital 

Costs Year 1 FTEs

Cont. Pneumatic Bleed Device $ 1,058 $ - 0.01 $ 338 $ - 0.00

Low Pneumatic Bleed Device $ 54,563 $ - 0.36 $ 34,547 $ - 0.23

Pneumatic Pump Venting $ 42,643 $ - 0.28 $ 24,176 $ - 0.16

AGR Vent Stacks (CO2 only) $ 2,756 $ 6,300 0.02 $ 2,756 $ 6,300 0.02

Dehydrator Vent Stacks $ 56,175 $ - 0.37 $ 30,094 $ - 0.20

Well Venting Liquids Unloading (Method 1) $ 59,063 $ 90,000 0.39 $ 14,766 $ 22,500 0.10

Well Venting Liquids Unloading (Method 2) $ 99,281 $ - 0.66 $ 65,859 $ - 0.44

Conventional Gas Well Venting 

Completions/Workovers $ 75,825 $ - 0.51 $ 62,400 $ - 0.42

Unconventional Gas Well Venting 

Completions/Workovers $ 85,500 $ 60,000 0.57 $ 21,375 $ 15,000 0.14

Storage Tanks $ 562,406 $ 2,142,500 3.75 $ 284,156 $ 1,082,500 1.89

Well Testing $ - $ - $ - $ - 

Assoc. Well Gas Venting & Flaring $ 1,500 $ 6,000 0.01 $ 750 $ 3,000 0.01

Centrifugal Compressor Wet Seal Oil Degassing Vent $ - $ - $ - $ - 

Reciprocating Compressor Rod Packing Vents

Compressor Blowdown Valve Leak

Compressor Blowdown Vent (Unit Isolation Valve Leak)

Fugitive Sources - component basis $ 674,886 $ - 4.50 $ 362,586 $ - 2.42

Gathering pipeline fugitives-miles $ 1,800 $ - 0.01 $ 1,800 $ - 0.01

Coal Bed Methane Produced H2O Emissions

Hydrocarbon Liquids Dissolved CO2

Produced H2O Dissolved CO2

General Costs (per field basis) $ 686,250 $ 303,000 4.58 $ 171,563 $ 75,750 1.14

TOTAL $ 3,795,518 $ 2,798,900 25 $ 1,781,003 $ 1,303,750 12

Basin/Field Count

Compliance Cost/Facility

9

 $ 732,713 

15

 $ 205,650 

Emission Source 

 $ 106,313 0.71 $ 54,338 0.36

Basin @25k Field @25k

 $ 189,000 $ 96,600 

 $ 1,285,500 $ 2,100 8.57 $ 649,500 $ 2,100 4.33
Page | 15

Table A-3: Onshore Production Year 2 Compliance Costs Based on Independent Estimates

 Year 2 Labor 

Costs 

 Year 2 

Capital Costs Year 2 FTEs

 Year 2 Labor 

Costs 

 Year 2 Capital 

Costs Year 2 FTEs

Cont. Pneumatic Bleed Device $ 159 $ - 0.00 $ 51 $ - 0.00

Low Pneumatic Bleed Device $ 4,365 $ - 0.03 $ 2,764 $ - 0.02

Pneumatic Pump Venting $ 2,437 $ - 0.02 $ 1,382 $ - 0.01

AGR Vent Stacks (CO2 only) $ 1,395 $ 6,300 0.01 $ 1,395 $ 6,300 0.01

Dehydrator Vent Stacks $ 50,925 $ - 0.34 $ 27,281 $ - 0.18

Well Venting Liquids Unloading (Method 1) $ 37,125 $ - 0.25 $ 9,281 $ - 0.06

Well Venting Liquids Unloading (Method 2) $ 55,598 $ - 0.37 $ 36,881 $ - 0.25

Conventional Gas Well Venting 

Completions/Workovers $ 53,078 $ - 0.35 $ 43,680 $ - 0.29

Unconventional Gas Well Venting 

Completions/Workovers $ 36,000 $ - 0.24 $ 9,000 $ - 0.06

Storage Tanks $ 482,063 $ 2,142,500 3.21 $ 243,563 $ 1,082,500 1.62

Well Testing $ - $ - 0.00 $ - $ - 0.00

Assoc. Well Gas Venting & Flaring $ 600 $ 6,000 0.00 $ 300 $ 3,000 0.00

Centrifugal Compressor Wet Seal Oil Degassing Vent $ - $ - 0.00 $ - $ - 0.00

Reciprocating Compressor Rod Packing Vents

Compressor Blowdown Valve Leak

Compressor Blowdown Vent (Unit Isolation Valve Leak)

Fugitive Sources - component basis $ 67,489 $ - 0.45 $ 36,259 $ - 0.24

Gathering pipeline fugitives-miles $ 600 $ - 0.00 $ 600 $ - 0.00

Coal Bed Methane Produced H2O Emissions

Hydrocarbon Liquids Dissolved CO2

Produced H2O Dissolved CO2

General Costs (per field basis) $ 396,750 $ 3,000 2.65 $ 99,188 $ 750 0.66

TOTAL $ 2,574,490 $ 2,346,800 17 $ 1,212,444 $ 1,189,150 8

Basin/Field Count

Compliance Cost/Facility

9 15

 $ 546,810 $ 160,106 

 $ 1,285,500 $ - 8.57 $ 649,500 $ - 4.33

Emission Source 

Basin @25k Field @25k

 $ 100,406 $ 189,000 0.67 $ 51,319 $ 96,600 0.34
Page | 16

Table A-4: Onshore Production Emission Source Counts

Basin @25k Field @25k

Cont. Pneumatic Bleed Device 47 15

Low Pneumatic Bleed Device 5,820 3,685

Pneumatic Pump Venting 1,083 614

AGR Vent Stacks (CO2 only) 3 3

Dehydrator Vent Stacks 140 75

Well Venting Liquids Unloading (Method 1) 180 45

Well Venting Liquids Unloading (Method 2) 2,118 1,405

Conventional Gas Well Venting 

Completions/Workovers (Method??) 1,011 832

Unconventional Gas Well Venting 

Completions/Workovers (Method??) 120 30

Storage Tanks 4,285 2,165

Well Testing 0 0

Assoc. Well Gas Venting & Flaring 20 10

Centrifugal Compressor Wet Seal Oil 

Degassing Vent 0 0

Reciprocating Compressor Rod Packing Vents

Compressor Blowdown Valve Leak

Compressor Blowdown Vent (Unit Isolation 

Valve Leak)

Fugitive Sources - component basis 1,079,817 580,138

Gathering pipeline fugitives-miles 2,404 910

Coal Bed Methane Produced H2O Emissions

Hydrocarbon Liquids Dissolved CO2

Produced H2O Dissolved CO2

General Costs (per field basis) 60 15

4,285 2,165

Estimated Source Count

Emission Source 

315 161
Page | 17

Tables A-5: Basis For Adjustments to EPA Costs for Onshore Processing Plants
Page | 18

Capital Cost

Equipment 

Life (yrs)

Equivalent 

Annualized cost 

(7% interest rate 

assumed) O&M Costs

Activity First Year Subsequent Year

Equipment (selection, purchase, installation) $7,000 $5 $1,701 $400 $2,101 $2,501

Contractor Support (Fugitives)** $1,841 $1,841 $1,841

Recordkeeping $5,000 $5,000 $5,000

Travel $500 $500 $500

Total $7,000 $7,741 $9,442 $9,842

Capital Cost

Equipment 

Lifetime 

(yrs)

Equivalent 

Annualized cost 

(7% interest rate 

assumed) O&M Costs

Activity First Year Subsequent Year

Equipment (selection, purchase, installation) $53,200 $5 $12,974 $12,974 $12,974

Contractor Support (Fugitives)** $3,039 $3,039 $3,039

Recordkeeping $8,000 $8,000 $8,000

Travel $500 $500 $500

Total $53,200 $12,974 $11,539 $24,513 $24,513

Capital Cost

Equipment 

Lifetime 

(yrs)

Equivalent 

Annualized cost 

(7% interest rate 

assumed) O&M Costs

Activity First Year Subsequent Year

Equipment (selection, purchase, installation) $53,200 $5 $12,974 $12,974 $12,974

Contractor Support (Fugitives)** $4,237 $4,237 $4,237

Recordkeeping $10,000 $10,000 $10,000

Travel $500 $500 $500

Total $53,200 $12,974 $14,737 $27,711 $27,711

ODC Cost

ODC Cost

Medium Facility

Large Facility

Small Facility

ODC Cost
Page | 19

Tables A-6: Basis For Adjustments to EPA Costs for Onshore Transmission Compression

Labor Hours

Activity Year 1 Year 2 Year 1 Year 2 Year 1 Year 2 Year 1 Year 2 Year 1 Year 2 Year 1 Year 2

Planning* 1 1 2 1 4 2 3 1 $984 $456

QA/QC $0 $0

Record Keeping* 0 0 3 3 3 3 7 4 $1,187 $869

Sampling 0 0 2 2 26 26 0 0 27 27 $3,783 $3,783

Reporting 2 2 6 6 12 12 8 8 $2,580 $2,580

Total $8,534 $7,687

Activity Year 1 Year 2 Year 1 Year 2 Year 1 Year 2 Year 1 Year 2 Year 1 Year 2 Year 1 Year 2

Planning* 2 1 3 2 7 3 5 2 $1,528 $714

QA/QC

Record Keeping* 0 0 4 3 4 3 7 4 $1,354 $952

Sampling 0 0 6 6 26 57 0 0 51 51 $5,615 $8,095

Reporting 3 3 10 10 22 22 12 12 $4,310 $4,310

Total $12,807 $14,071

Activity Year 1 Year 2 Year 1 Year 2 Year 1 Year 2 Year 1 Year 2 Year 1 Year 2 Year 1 Year 2

Planning 5 2 12 6 27 18 17 8 $5,625 $2,963

QA/QC

Record Keeping 2 1 10 6 14 8 10 6 $3,370 $1,960

Sampling 0 0 2 2 26 26 0 0 46 46 $4,853 $4,853

Reporting 2 2 6 6 14 14 8 8 $2,740 $2,740

Total $16,588 $12,516

Large Facility

Senior Mgmt Middle Mgmt Junior Eng Sr Operator Technician Labor Cost per Year

Medium Facility

Senior Mgmt Middle Mgmt Junior Eng Sr Operator Technician Labor Cost per Year

Senior Mgmt Middle Mgmt Junior Eng Sr Operator Technician Labor Cost per Year

Small Facility

$150.00 $120.00 $80.00 $75.00 $55.20
Page | 20

Capital Cost

Equipment 

Life (yrs)

Equivalent 

Annualized cost 

(7% interest rate 

assumed) O&M Costs

Activity First Year Subsequent Year

Equipment (selection, purchase, installation) $4,200 $5 $1,024 $400 $1,424 $1,824

Contractor Support (Fugitives)** $1,841 $1,841 $1,841

Recordkeeping $5,000 $5,000 $5,000

Travel $500 $500 $500

Total $4,200 $7,741 $8,765 $9,165

Capital Cost

Equipment 

Lifetime 

(yrs)

Equivalent 

Annualized cost 

(7% interest rate 

assumed) O&M Costs

Activity First Year Subsequent Year

Equipment (selection, purchase, installation) $11,200 $5 $2,732 $2,732 $2,732

Contractor Support (Fugitives)** $3,039 $3,039 $3,039

Recordkeeping $8,000 $8,000 $8,000

Travel $500 $500 $500

Total $11,200 $2,732 $11,539 $14,271 $14,271

Capital Cost

Equipment 

Lifetime 

(yrs)

Equivalent 

Annualized cost 

(7% interest rate 

assumed) O&M Costs

Activity First Year Subsequent Year

Equipment (selection, purchase, installation) $15,400 $5 $3,756 $3,756 $3,756

Contractor Support (Fugitives)** $4,237 $4,237 $4,237

Recordkeeping $8,000 $8,000 $8,000

Travel $500 $500 $500

Total $15,400 $3,756 $12,737 $16,493 $16,493

Small Facility

ODC Cost

Medium Facility

ODC Cost

Large Facility

ODC Cost
Page | 21

Tables A-7: Basis For Adjustments to EPA Costs for Underground Storage Facilities

Labor Hours

Activity Year 1 Year 2 Year 1 Year 2 Year 1 Year 2 Year 1 Year 2 Year 1 Year 2 Year 1 Year 2

Planning* 1 1 2 1 4 2 3 1 $984 $456

QA/QC $0 $0

Record Keeping* 0 0 3 3 3 3 7 4 $1,187 $869

Sampling 0 0 0 0 16 16 0 0 10 10 $1,804 $1,804

Reporting 2 2 6 6 12 12 8 8 $2,580 $2,580

Total $6,555 $5,709

Activity Year 1 Year 2 Year 1 Year 2 Year 1 Year 2 Year 1 Year 2 Year 1 Year 2 Year 1 Year 2

Planning* 2 1 3 2 7 3 5 2 $1,528 $714

QA/QC

Record Keeping* 0 0 4 3 4 3 7 4 $1,354 $952

Sampling 0 0 0 0 16 47 0 0 32 32 $3,046 $5,526

Reporting 3 3 10 10 22 22 12 12 $4,310 $4,310

Total $10,238 $11,502

Activity Year 1 Year 2 Year 1 Year 2 Year 1 Year 2 Year 1 Year 2 Year 1 Year 2 Year 1 Year 2

Planning 4 1 12 6 23 15 13 6 $4,855 $2,498

QA/QC

Record Keeping 2 1 10 6 14 8 10 6 $3,370 $1,960

Sampling 0 0 0 0 16 16 0 0 27 27 $2,764 $2,764

Reporting 2 2 6 6 14 14 8 8 $2,740 $2,740

Total $13,729 $9,962

Large Facility

Senior Mgmt Middle Mgmt Junior Eng Sr Operator Technician Labor Cost per Year

Medium Facility

Senior Mgmt Middle Mgmt Junior Eng Sr Operator Technician Labor Cost per Year

Senior Mgmt Middle Mgmt Junior Eng Sr Operator Technician Labor Cost per Year

Small Facility

$150.00 $120.00 $80.00 $75.00 $55.20
Page | 22

Capital Cost

Equipment 

Life (yrs)

Equivalent 

Annualized cost 

(7% interest rate 

assumed) O&M Costs

Activity First Year Subsequent Year

Equipment (selection, purchase, installation) $4,200.00 5 $1,024.34 $400.00 $1,424.34 $1,824.34

Contractor Support (Fugitives)** $1,841.00 $1,841.00 $1,841.00

Recordkeeping $5,000.00 $5,000.00 $5,000.00

Travel $500.00 $500.00 $500.00

Total $4,200 $7,741 $8,765 $9,165

Capital Cost

Equipment 

Lifetime 

(yrs)

Equivalent 

Annualized cost 

(7% interest rate 

assumed) O&M Costs

Activity First Year Subsequent Year

Equipment (selection, purchase, installation) $11,200.00 5 $2,731.58 $2,731.58 $2,731.58

Contractor Support (Fugitives)** $3,039.00 $3,039.00 $3,039.00

Recordkeeping $8,000.00 $8,000.00 $8,000.00

Travel $500.00 $500.00 $500.00

Total $11,200.00 $2,731.58 $11,539.00 $14,271 $14,271

Capital Cost

Equipment 

Lifetime 

(yrs)

Equivalent 

Annualized cost 

(7% interest rate 

assumed) O&M Costs

Activity First Year Subsequent Year

Equipment (selection, purchase, installation) $15,400.00 5 $3,755.92 $3,755.92 $3,755.92

Contractor Support (Fugitives)** $4,237.00 $4,237.00 $4,237.00

Recordkeeping $8,000.00 $8,000.00 $8,000.00

Travel $500.00 $500.00 $500.00

Total $15,400.00 $3,755.92 $12,737.00 $16,493 $16,493

ODC Cost

Small Facility

ODC Cost

Medium Facility

ODC Cost

Large Facility
Page | 23

Tables A-8: Basis For Adjustments to EPA Costs for LNG Import Facilities

Activity Year 1 Year 2 Year 1 Year 2 Year 1 Year 2 Year 1 Year 2 Year 1 Year 2 Year 1 Year 2

Planning* 3 1 16 7 38 19 15 7 $6,535 $3,051

QA/QC

Record Keeping* 2 1 3 2 16 9 2 2 $2,090 $1,163

Sampling 0 0 3 3 0 23 0 0 34 34 $2,209 $4,049

Reporting 0 0 4 4 27 27 0 0 $2,615 $2,615

Total $13,449 $10,878

Medium Facility

Senior Mgmt Middle Mgmt Junior Eng Sr Operator Technician Labor Cost per Year

Capital Cost

Equipment 

Lifetime 

(yrs)

Equivalent 

Annualized cost 

(7% interest rate 

assumed) O&M Costs

Activity First Year Subsequent Year

Equipment (selection, purchase, installation) $5,600 $5 $1,366 $1,366 $1,366

Contractor Support (Fugitives)** $3,039 $3,039 $3,039

Recordkeeping $2,000 $2,000 $2,000

Travel $500 $500 $500

Total $5,600 $1,366 $5,539 $6,905 $6,905

Medium Facility

ODC Cost
Page | 24

APPENDIX III

Legal Authority and Linkage to CAA Regulations

EPA states in the Federal Register notice for the proposed rule that it is proposing the rule “under its existing

CAA authority,” specifically, Section 114(a)(1) of the CAA. 75 Fed. Reg. 18608, 18610-11 (Apr. 10, 2009). 

As EPA notes in the administrative record for the MRR rule it finalized last year, however, and as it states again 

in the current proposal, EPA faced a choice of proceeding under Section 114 or under the Consolidated 

Appropriations Act. Id. at 18610. As EPA recognized in last year’s administrative record, however, “[b]y 

proceeding using the authority of the Appropriations Act, rather than the Clean Air Act, EPA would be limiting 

the scope and time period that the program would be effective, consistent with the appropriations law that made 

available the funds to create this program.” (See Doc. No. EPA-HQ-OAR-2008-0508-0056.2.) Possibly in an 

effort to justify monitoring as well as reporting requirements and to avoid limitations on the duration of the

program, EPA chose to rely on Section 114 of the CAA. 

El Paso respectfully submits that, by relying on Section 114 as authority for the proposed rule, EPA exceeds its 

statutory authority under the Clean Air Act. EPA’s only authority for the proposed rule is under the 

Consolidated Appropriations Act. That authority is limited in scope to reporting requirements, not monitoring 

requirements, and is limited in duration to the fiscal year for which the funds are appropriated. 

(i) There is no direct authority under the CAA for the proposed rule

EPA has expressed reservations about its authority to promulgate the proposed rule under Section 114, and 

these reservations are well founded. (See Doc. No. EPA-HQ-OAR-2008-0508-0056.2.) Section 114 provides 

EPA with the authority to seek information “for the purpose of developing or assisting in the development of

any implementation plan under Section 7410 [. . .], any standard of performance under Section 7411 of this title, 

an emission standard under Section 7412 of this title, or any regulation of solid waste combustion under 7429 of 

this title” or for “carrying out any provision of this chapter.” Because GHGs are not yet subject to Section 110, 

111, or 112, Section 114 does not authorize EPA to promulgate the monitoring and reporting requirements of 

the proposed rule. Section 114 can only be used for regulated pollutants.

Before standards can be developed under Section 110, a NAAQS must be set. 42 U.S.C. § 7408(a)(1). EPA 

has yet to determine if GHGs are a regulated pollutant under the Act or develop a standard under Section 110 

that would be a NAAQS determination. Section 114 could not be used to “develop or assist in the 

development” of an implementation plan until the underlying reasoning and basis was established for 

developing such a plan.

As with Section 110, Sections 111 and 112 would require a determination that GHGs are pollutants subject to 

the Act before these sections would become applicable. Even then Sections 111 and 112 are not applicable 

until after source categories are established and other statutory criteria are met. EPA could not, therefore, 

utilize Section 114 to assist in developing a standard where there is not yet a reason or basis for setting the 

standard.

Section 114 also provides authority for EPA to seek information for “carrying out any provision of this 

chapter.” CO2 is not, however, subject to this “chapter.” The term “chapter” means Chapter 85 of Title 42, i.e.

the Clean Air Act Although the U.S. Supreme Court decided in Massachusetts that CO2 is an “air pollutant,” 

EPA has not yet determined that CO2 is a “pollutant subject to the Act.” Until EPA makes a final endangerment 

finding and a control requirement is established under the Act, CO2 is not a “pollutant subject to the Act” and 

thereby not a “pollutant subject to the Chapter.” Nor can EPA rely on its authority to do studies and 
Page | 25

investigations under Section 103 of the CAA to bootstrap into authority under Section 114 for the proposed 

rule. Section 103 does not mention the words “monitoring” or “reporting,” only words such as “studies,” 

“surveys,” “investigations,” and similar discrete, one-time or time-limited activities. A rule of statutory 

construction known as ejusdem generis provides that ‘where general words follow the enumeration of particular 

classes of things, the general words are most naturally construed as applying only to things of the same general 

class as those enumerated.’ Am. Mining Congress v. USEPA, 824 F.2d 1177, 1189 (D.C. Cir. 1987). General 

phrases such as “carrying out any provision of this chapter” are, therefore, to be interpreted narrowly as 

consistent with, and not expanding, the list that proceeds the general phrase. The expansive interpretation EPA 

advocates would violate this rule. The catch-all phrase should not, therefore, be understood to expand Section 

114 to authorize monitoring and reporting on pollutants not yet considered “pollutants subject to the Act.” 

EPA’s expansive interpretation of Section 114 would, in addition, obviate the need for many express 

Congressional directives found elsewhere in the CAA, violating yet another rule of statutory construction. 

Section 821 of Public Law 101-549, for example, expressly authorizes EPA to require monitoring and reporting 

for CO2 on certain electric generating units. EPA’s authority under Section 821 is limited, however, to certain 

power generating units subject to the provisions of the Acid Rain program. If EPA had the authority it now 

claims to have under Section 114 (bootstrapped by Section 103), it would have been unnecessary for Congress 

to enact Section 821 to establish ongoing CO2 monitoring and reporting requirements for power generating 

units, not to mention the monitoring requirements in Section 112, Title IV, and Title VI of the CAA, among 

others. A canon of statutory construction is that one section of an Act should not be read so as to usurp or make 

another section superfluous. See TRW Inc. v. Andrews, 534 U.S. 19, 31 (2001) (“It is ‘a cardinal principle of 

statutory construction that a statute ought, upon the whole, to be so construed that, if it can be prevented, no 

clause, sentence, or word shall be superfluous, void, or insignificant.’ Courts are ‘reluctant to treat statutory 

terms as surplusage in any setting.’”) EPA’s expansive interpretation of Section 114 would render many other 

sections of the CAA surplusage.

Finally, EPA’s proposed, expansive use of Section 114 runs counter to its longstanding use of this section in 

the past. EPA’s use of Section 114 in the past has properly been limited to issuing Information Collection 

Requests (“ICRs”) to collect data to develop programs such as the MACT rules and CAMR. ICRs have 

historically been limited to collecting data from specific sources over a discrete period of time, usually relying 

on existing data or a subset of the potential universe of sources, or both. Section 114 has not previously been 

used to justify an essentially economy-wide, permanent rule that requires all affected sources to submit new 

data annually on an ongoing basis and imposes new monitoring and measurement processes to collect such 

data. EPA’s proposed use of Section 114 to authorize the proposed monitoring and reporting rule is 

inconsistent with its longstanding prior use of this section. If challenged, therefore, the agency’s expansive 

interpretation would be entitled to minimal, if any, deference. See, e.g., Watt v. Alaska, 451 U.S. 259, 273 

(1981). 

EPA itself has expressed reservations about its authority to interpret Section 114 as broadly as the rule proposes, 

as reflected in the administrative record for the proposed rule. (See Doc. No. EPA-HQ-OAR-2008-0508-

0056.2.) EPA’s reservations about its authority to promulgate the proposed rule under Section 114 are well 

founded. For the reasons discussed above, among others, the proposed expansion of the agency’s authority 

under Section 114 is an abuse of discretion, not in accordance with the law, and in excess of the agency’s 

statutory authority. 
Page | 26

(ii) Authority under the Consolidated Appropriations Act is limited in time and 

duration

For the reasons discussed above, EPA does not have direct authority to promulgate the proposed monitoring and 

reporting rule under the CAA. EPA’s only possible authority for the proposed rule is, therefore, the 

Consolidated Appropriations Act. If the Consolidated Appropriations Act provides authority for this rule, 

however, it is limited in scope to reporting requirements in duration to the fiscal year for which the funds are 

appropriated.

As EPA has recognized, the statutory language of the Appropriations Act “does not, in its own terms, indicate 

what authority EPA is to invoke in order to require mandatory emissions reporting of greenhouse gases or 

otherwise indicate a policy purpose for this endeavor.” (See Doc. No. EPA-HQ-OAR-2008-0508-0056.2). By 

failing to do so, Congress has asked EPA to establish a “reporting program despite Congress’s unwillingness to 

date to itself enact a comprehensive GHG reporting and control regime . . . . based on nothing more than one 

sentence, on page 284, of a 612 page law appropriating funds for virtually the entire federal government and 

covering thousands of different policy and funding matters.” By failing to delineate the policy behind, and 

boundaries of, this delegated authority, the Appropriations Act violates the separation of powers doctrine. 

Congress cannot delegate to an administrative agency Congress’s law-making power or the power to exercise 

the discretion to modify a statute or power to add parties or acts to those punishable under the statute. See St. 

Louis Terminal Merchants’ Bridge Ry. Co., 188 F. 181, 191 (1911). Where Congress seeks to delegate 

rulemaking authority to the executive branch, it must set out intelligible principles to guide the agency. See

Railway Executives’ Ass’n v. Skinner, 934 F.2d 1096 (9th Cir. 1991) (citing Ministretta vs. United States, 488 

U.S. 361 (1989)). There is a serious question as to whether one sentence in the Appropriations Act is sufficient 

to meet these standards.

If the monitoring and reporting rule were to survive Constitutional challenge, the proposed rule would still go 

beyond EPA’s statutory authority as set out in the Appropriations Act. The Act provides, in relevant part:

Of the funds provided in the Environmental Programs and Management account, not less than 

$3,500,000 shall be provided for activities to develop and publish a draft rule not later than 9 

months after the date of enactment of this Act, and a final rule not later than 18 months after 

the date of enactment of this Act, to require mandatory reporting of greenhouse gas emissions 

above appropriate thresholds in all sectors of the economy of the United States.

H.R. 2764 at 285 (emphasis added). To the extent that the Appropriations Act authorizes anything beyond what 

is already authorized by the Clean Air Act—and it is doubtful that it does—the Appropriations Act provides 

authority only for reporting, not for monitoring. Appropriations legislation is to be construed narrowly. The 

Supreme Court has stated: “[A] fundamental principle of appropriation law is where Congress merely 

appropriates lump-sum amounts without statutorily restricting what can be done with those funds, a clear 

inference arises that it does not intend to impose legally binding restrictions, and indicia in committee reports 

and other legislative history as to how the funds should or are expected to be spent do not establish any legal 

requirements on the agency.” Lincoln v. Vigil, 508 US 182, 192-93 (1993); Cherokee Nation v. Leavitt, 543 

US 631, 646 (2005) (“The relevant case law makes clear that restrictive language contained in Committee 

Reports is not legally binding.”). Regardless of whether reporting is authorized under the Appropriations Act, 

therefore, monitoring is not.

Moreover, If EPA uses the Consolidated Appropriations Act as authority, the emissions reporting rule would be 

limited to the time period and scope of the appropriation—one year. EPA itself stated in the original preamble 

to the GHG reporting rule that: “By proceeding using the authority of the Appropriations Act, rather than the 

Clean Air Act, EPA would be limiting the scope and time period that the program would be effective, consistent 

with the appropriations law that made available the funds to create this program.” See EPA-HQ-OAR-2008-
Page | 27

0508-0056.2. The D.C. Circuit Court has stated that there is a strong presumption that appropriations acts do 

not substantively change existing law, and if they do, it is only for one fiscal year. Building & Construction 

Trades Department, AFL-CIO v. Martin, 961 F.2d 269, 273 (D.C. Cir.), cert. denied, 506 U.S. 915 (1992).

EPA has recognized that it is questionable whether the Appropriations Act provides any authority beyond that 

already contained in the CAA. See EPA-HQ-OAR-2008-0508-0056.2. If it does, however, that authority is 

limited to reporting of existing data and to the time for which the funds are appropriated. The Appropriations 

Act does not authorize a permanent requirement to directly measure or estimate new data and report it on an 

annual, ongoing basis to EPA.