June 1 1

, 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 Register 1 on April 1 2 , 20 10 (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 natura l 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, 1 1 processing plants ( pe r proposed definition in the Subpart W rule)

, 11 underground storage facilities, 40 offshore production facilities

, 62 onshore production reporting fields, and one Liquefied Natural G as (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 change 2 . We have received approval from the Federal Energy Regulatory Commission (FERC)

to construct a multi

- billio n 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 bein g the first natural gas company to certify its total GHG emissions f rom 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 lea der, we understand

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

2 http://elpaso.com/CSR/neighbortohave.htmlthe 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 32 3 an d Western Climate Initiative (WCI) rule development 4 . 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 t echnical 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 g ood 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

protoc ol 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, economy

wide GHG reporting program

. P lease feel free to contact me at (713) 420

- 7913 or fiji.george@elpaso.com , with questions or for further information or clarifica tion.

Sincerely,

Fiji George Carbon Strategies Director El Paso Corporation

3 Multiple 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 I II : Legal Authority and Linkage to CAA RegulationsPage | 1 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. Preambl e 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.

— E l 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

un derestimated 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 method s to assist with the initial year ap plicability

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 Energ y 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 reb uttable 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 Pas o 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 o ffshore petroleum and natural gas production operators due to

similar emission sources , functional use and production practices

.Page | 2 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 dehy drator 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 ventin g 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 a n alternate

method be added to allow blowdown volumes be corrected to standa rd 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. P roposed 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 pro vided 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 storag e facilities.Page | 3 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 t o 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 emi ssion 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 CO 2 . — El Paso urges EPA to limit the applicability of the requirements for dissolved CO 2 specifically to onshore oil and gas operations that utilize high CO 2 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 dat a 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 revis ion 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.Page | 4 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 fo r information under Section 114. E l Paso’s comments on the legal aspects of the Subpart W re

- proposal are covered in more detail in Section XXV I of this

Attachment.

I. Preamble Section II

. (A

. ) on Page 18612

— EPA’s proposed dates for initial data collection and initial submittal of reports a re not feasible. El Paso requests the EPA to consider a June 30 submittal deadline for all emission reports related to Subpart W.

O n page 18612 of the proposed rules, the EPA states that the facilities would be required to collect data (i.e. conduct mo nitoring) 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 a n 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 repor t ing 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

followin g:

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. Monitori ng can be conducted anytime during the y ear and not necessarily on January 1,

2011 or even during the first quarter.

El Paso believe s 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 reas onable consideration to an important aspect of the challenges pres ented by the Subpart W rule

.

These challenges are outlined below:

A. U nlike 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 wil l 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 inform ation 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, acc urate, 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 co mpany 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

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

facilities 5 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 need ed to provide our Designated Representative a reasonable assurance of compliance. Compliance with the rules will, therefore, requir e 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 p olicies 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 in i tiation of co mpliance monitoring in 2011, the EPA will likely b e creating an unsustainable, unver ifiable 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 o f 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 contai ning 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 6 50 hours , i.e. approximately 9 hours per facility.

For S ubpart 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 65 0+ additional stationary fuel combustion

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

w ill 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 S ubpart 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 type s ; 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 S ubpart 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”. Th e 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 app endix B to 40 C FR 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 fugitiv e 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 suggest s for : 1) allowing additional time to develop quality monito ring plans for compliance with S ubpart W, i.e. at least until April 1, 2011 ; and 2) incorporat ing similar special provisions for reporting year 2011, as currently prescribed under Section 98.3(d), allowing the use of best available monitoringPage | 7 methods in the first quarter of 2011 for any parameter (i.e., inlet/outlet metered volumes, GHG

concentrations of inle t/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 . M ost 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 p ossible for the regulated community to set up systems and programs w ithin 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 resear ch 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 wit h 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 b y 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 report 6

, 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 p roposed 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 p ersonnel safe, and sampling techniques

6 PR

- 246

- 9526, T. Howard, R. Kantamaneni, and G. Jones December 1998Page | 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 e xplosive 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 o f work remain below safe levels). L eak 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

pot entially larger than at stan dard 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

haz ards 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 High

Flow Sampler to a location where large concentrations are not expec ted. Static electricity

dis charges 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 h arnesses 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, t ag and lock

out 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 discuss ed 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. I njury could result should a measurement specialist have his head or hands in the path of the blow down. Personnel must also be t rained 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 syste m. 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) H i

- 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 conditio ns 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 (s ix 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 o nly 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 comp ressor units 7 , and starting a unit that is idle 8

, 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 activities 9 . 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 wo uld 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 overhea ting 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 the re 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 i nto 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 a re available publicly and can be found at : 1) The f ollowing link for each El Paso pipeline subsidiary: http://elpaso.com/postings/default.asp ; then 2) Reference link s on side bar

titled “Notices ” and “ P lanned 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 c apacity

. 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 mile s of interstate pipeline

, are

current ly 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 c ompressor 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 automa tion 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 r eporting and do not include comprehensive monitoring program proposed by the EPA under Subpart W

. By failing to consider these costs, EPA has di s regarded an important aspect of the challenges presented by compliance with the pro p osed 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 prepar ing 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 & ProceduresPage | 12 still subst antial 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 o ne quarter after the end of the calendar year, for the above mentioned reasons. Therefore, w e 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 a nd natural gas distribution sectors. Therefore, to avoid confusion, the E PA 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 B asis as O pposed to C ost P rohibitive 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 with in a reporting field or area that in the

aggregate emits over 2 5,000 metric tons per year. Through this rule development, in determining the appropriate threshold and “facility” definition s, 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, o n 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. How ever, as outlined in Table W

- 3 o n page 18619, EPA concludes that about 55% of the emissions are covered by e mploying 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 underestim ated 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 I mpact 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

detail ed cost estimate for our E&P operations and the number of sources associated with our upstream operations for t wo 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 emiss ions 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 CO 2 e :

El Paso constructed a detailed cost analysis on a source

- by

- source basis for all of its operations that exceed 25,000 metric tons CO 2 e at the basin level. For the upstream operations only, the proposed rule will require that more than 1 million individ ual 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 complian ce for Subpart W will require over 25 full time equivalents 10 (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 10 K t hresholds

.

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 $5.6MMPage | 14 **•** Dissolved CO 2 : 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: 1.0 5 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 CO 2 e, El Paso has 9 such basin

level repor ting 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 CO 2 e :

For comparison, El Paso also examined the costs and emissions coverage based on defining the E&P reporting un it at a production field level emitting > 25,000 metric tons CO 2 e (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.

B ased on the field level approach and 25,000 metric tons threshold, the estimated first year compliance wi ll 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 EstimatePage | 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 CO 2 e 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 g as 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 Administratio n. 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 method s to assist with determination

.

EPA has not proposed a “ screening” method to determine initial applicability to the r ule 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 method s :

1) A 10,000 metric tons CO 2 e threshold established based on combustion emissions using procedures outlined in Subpart C ; or 2) Allow u se of best available data to estimate GHG emissions and determine applicability against 25,000 metric tons CO 2 e 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 inv entory

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 emis s ions :

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

CO 2 e 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 scr eening 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 tons 11 from facilities subject to the proposed rule and over 415 million metric tons 12 from the entire sector. While

these estimates are almost double of EPA’s official inventory 13 presented below in T able 3 , the

breakdown between methane and CO 2 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 provide s adequat e buffer conside ring 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 app licability or non

applicability of smaller fac ilities.

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 a pproach 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 avail able 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 2 5,000 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

- 2008Page | 17 over 25,000 metric tons . Once a facility’s estimated emissions based on best available methods exceed 25,000 metric tons , t he 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 t ons CO 2 e.

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

determinat ion 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 responden ts to “benefit from a

re butt able 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 effor ts 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 metri c

tons CO 2 e 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 previous ly mentioned, El

Paso recomme nds 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 t ransitional p lan for the n atural gas s ector 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 rel ated 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 CO 2 Eq.). Reproduced from Figure ES

- 4 EPA Inventory 14

Tab le 3 : 2008 Greenhouse Gas Emissions for the Natural Gas Industry and the U.S. (Tg CO 2 equivalent)

Energy

Related

CO 2 Emissions Non

Combustion

CO 2 Emissions CO 2 CH 4 Total

CO 2 e

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, 2010Page | 19 As noted in Table 3 , t he 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 syste m profile. I n other words, per this EPA inventory 15 , 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

sh ould 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 pro grams [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 sys tems, 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 alternativ e 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 c urrent 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 a pplicable 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 nec essary 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 s uch 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 repor t all their GHG emissions including their Subpart W sources using final EPA monitoring and reporting methods. U nder this approach , the 2012 report ing will be limited to sources that are over the 25,000 metric tons threshold for Subpart C. Thereafter,

addi tional 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

201 1 All “facilities” subject to Subpart C All Subpart C and W sources identified by the EPA in final rule for the 201 1

facilities

. 201 2 201 1 facilities + 1/3 of the remaining

f

acilities over 25,000 metric tons in

combined emissions All Subpart C and W sources identified by the EPA in final rule for the 201 2

facilities.

201 3 201 1 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.

201 4 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 M ethod + 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 facilit ies own ed or operate d 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 o f F acilities over 25K MT/yr CO 2 e

Reporting Year Reporting Method for Subpart W S ources

201 1 75%

- I ndustry methodologies/best available data

25%

- EPA final methods

201 2 50%

- I ndustry methodologies/best available data

50%

- EPA final methods

201 3 25%

- I ndustry methodologies/best available data

75%

- EPA final methods

201 4 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 . A ll Subpart W methods have associated uncertainties. We

have alrea dy 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 asse ssment 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. § 98.23 2(b) GHGs to report for o ffshore p etroleum and n atural g as p roduction

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 offshor e 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 prop osed 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 i nterim 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 t wo 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 oper ating 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 pr ocedures for the prioritization of

related leak reduction work

.

VIII. § 98.233(a) N atural 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 m odel 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 s hould 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 oth er 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 n atural gas inlet volume ;

**•** Metered n atural gas outlet volume;

**•** Volume weighted CO 2 content of inlet gas;

**•** Volume weighted CO 2 content of outlet gas.

Industry standard practices or current applicable regulations do not require continuous monitoring of natural gas flow and volume weighted CO 2 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

t o measure the inlet and outlet volumes for one amine unit. Given this high cost, an option to use estimated natural gas inlet and outlet vol umes should be allowed

.Page | 23 X. § 98.233(e) Dehydrator vent stacks

Industry standard practices or current applicable regulation s 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:

**•** N atural 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 interpret ation. 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 mode ling 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 us ing 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

- ov er 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 CH 4 and CO 2 in the produced gas. This approach uses information commonlyPage | 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 firs t 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. I n practice

, the blow

- down volume s are

corr ected 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 blow down volu mes. 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

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

emission estimates.

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

and document blowdowns , and these methodologies use t he 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 u nder Subpart W.

In addition, El Paso recommends an option be provided for the installation of permanent m eters
on blowdown vent stacks

.

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

El Paso estimates that gathering the data necess ary 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 approac hes 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 r eid vapor pressure;

**•** Ambient air temperature; andPage | 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 f or 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 separa tors, 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 mo nitoring 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 curren tly 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 TSD 17 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, E l Paso recommends that centrifugal compressors with wet seal s be surveyed as p er the “As Found” approach described under Section

XV and that emission factors be calcu lated 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 whe n 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 contributio n of wet seal leakage while the compressor unit is operating, the hypothetical emission factor for “Operating” wet seals (120.0

scfh CH 4 ) 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 CH 4 /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 emi ssion 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 CH 4 ) No. of Components Activity Factor (Hours Leaking / Y r ) Annual

Emissions (Mcf

CH 4 /Y r )

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 CH 4 /year) 3938Page | 27 XV. § 98.233(p) Reciprocating compressor rod packing venting: El Paso recommends monitoring in “ As F ound” 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, depres surized

El Paso recognizes and mentioned in its’ comments 18 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 is olation 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 allevi ate 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 proba bly 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, depressurize d” 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 w ould 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 i n capturing emissions. The increase in GHG emissions, difficulty in obt aining 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 sh ould consider

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

18 Docket ID No EPA

– HQ

– OAR

– 2008

– 0508Page | 28 To achieve the EPA’s goal of collecting meaningful and representative emissions data, the abovementioned operating s cenarios 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

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

modes 19 that can be related to the annual emissions from the facility

, El Paso recommends a hybrid monitoring approach to ensure a n ample data set of all modes over a r easonable amount

of time:

1. E ach 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

years 21

. 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 ye ar 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, i t is anticipated that the “ a s f ound” approach will result i n a large sample size of all

mo des. 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.

I n 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 (“ a s f o und”) , 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 ” m ode 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), compress or units in the El Paso transmission system spent over 50% of their time in each of the modes as follows: Operating (28.6%), St andby, Pressurized (34.7%), and Not Operating, Depressurized (36.8%). Consequently, “As Found” sampling should provide a repres entative 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 w ill 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 in dicates 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

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

amount of effort that does not provide a large improve ment in the accuracy of the reported

emissions . It would also distract from collect ing accurate data fr om 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 stil l be uncertainty in this method . The EPA Natural Gas Star program has previously developed emission factors for compresso r 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 th e 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. 7 th 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

c onductivity detectors, an d 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 co mponents 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 acce ss 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 equip ment 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 t wenty units at each site, the ratio of components to compressor units would be ap proximately 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 Main tenance 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 T he 2002 Clearstone study (EPA, 2002) 25 indicated that connectors and valves a ccounted 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 valv e 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, Secti on 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 reasonab le 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 component s fall under

S ection 98.233(r).

XVIII. § 98.233(q)(3) Leak detection an d 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 p opulation 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 v ast 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 th e geographic dispersion and number of small fugitive components, in addition to the disproportionate cost relative to the quantity of emissions, the rule should provide e quipment

level “population

- based” counts and emission factors from industry accepted p rotocols such as the API Compendium , INGAA guidelines, etc. to qu antify “population

- based ” f ugitive

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 acce ptable 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 ga s volumetric emissions at standard conditions (E s,n ) and mole percent of GHG in the natural gas (M i ). For underground natural gas storage facilities, M i shall be the annual average mole percent in the natural gas stored underground. However, “ n atural gas stored” typically include s 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 inje cted gas will only

be known for each injection cycle

. F ugitive emi ssions 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 facili ties.

XXI. § 98.233(x) Hydr o carbon liquids dissolved CO 2

The proposed rule requires determining the amount of CO 2 retained in hydrocarbon liquids and produced water after flashing in tanks. The rule requires collecting these samples once each quarter for eve ry 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 CO 2 specifically to onshore oil and g as operations that utilize high CO 2 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 sho uld 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 “th e 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 avail able 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 simila r 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 estimate s, 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 pressuriz ed compositions or dissolved CO 2 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. Therefo re, El Paso suggests eliminating certain reporting requirements as explained below.

1. For tank emissions identified using optical gas imaging instrument

P er Section 98.23 6(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 b e used to derive emission factors as the emissionsPage | 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 t he total throughput for centrifugal compressors with wet seal degassing vents and reciprocating compressor rod packing report pursuant to Section s 98.236(c)(17)(iii) and (18)(i), respectively . Again, this will increase the reporting burden as the

environme ntal 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 Desig nated 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 si gnificant 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 allo w 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 n atural gas p roduction f acility

Consistent with our comments under Section I I , 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 Geolo gists 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 onshor e petroleum and natural gas production facility reporting area

.

XXV. § 98.6 Definitions

Flare combustionPage | 35 The definition of flare combustion is poorly worded. We suggest the following:

Flare combustion emissions means emissions of CO 2 and N 2 O formed during the combustion process and emissions of CH 4 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 co rrect 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, S ection 114(a)(1) of the CAA. 75 Fed. Reg. 18608,

18610

- 11 (Apr. 12

, 2010 ). As EPA note s in the administrative record for the MRR rule it finalized last year

, however, and as it states again in the current proposal, EPA face d a choice of proceeding under S ection 114 or under the Consolidated Appropriations Act

. Id . at 18610. A s 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 t ime 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 i n an effort to justify monitoring as well as reporting req uirements and to avoid limitations on the duration of the program, EPA chose to rely on S ection 114 of the

CAA.

By relying on S ection 114 as authority for the proposed rule, EPA exceeded its statutory authority under the Clean Air Act. EPA’s only author ity 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 a uthority for this position is provided in Appendix I II 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 propo sed, fails to meet the standard of reasonableness applicable to governmental requests for i nformation

. Section 114 is the same section that authorizes EPA to issue administrative subpoenas to individual companies to collect information (also known as Sec tion 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 whet her 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 (1 st Cir. 1978); In Re Bunker Hill Mining and Smelti ng Company, 728 F. Supp. 626, 629 (D. Idaho 1990). We

believe Section 114 as proposed attempts to promulgate by rule a n ongoing monitoring and reporting requirement that would be disallowed by the court as unreasonably burdensome if EPA were to try to imp ose 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 i mportant 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 with out 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 pipeline 26 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, N 2 O and CO 2 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 Registr y’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 progra ms.

 El Pas o 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) report 28

.

 Since 1993, the El Paso Pipeline Group’s GHG emission red uctions from participation in the EPA Natural Gas Star Program totals over 55 billion cubic feet of natural gas, or approximately 20 million tons of CO 2 e. These and many other internal initiatives within El Paso have resulted in El Paso Pipeline Group achi eving 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 an d 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 proces s.

 On May 20, 2009, El Paso joined a c oalition 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 r educing climate pollution by financing conservation of tropical forests. The full agreement is a v ailable 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.htmlPage | 39  E l 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 gover nance, 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 industr y.

# APPENDICESPage | 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 wou ld 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 emis sions. 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 dur ing 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 mode 29 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, c ompanies 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 off

line

. It is El Paso’s understanding that there is no current standardized industry practice or method

of determin ing 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 a ssumed 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 R emote Terminal Units (R TU ’ 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 recirculati ng 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

pres surized 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 syst em 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 t he 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 tha n 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 d ocument 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, th e 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 t he 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 coll ected by

outside contractors and has approximately ten times as many measurements as the PRCI data set

. This data indicates an average of only 6% i ncrease 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 Pas o’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 do wn 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 d epressurized, 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: Emissi on 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 Leakage 1

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 t here 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 relativ e 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 le ak 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 stan dard 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 E quation 1:

LR Operating = ( N

CS

- Operating x EF CS

-- Operating ) + (N BDV x EF BD V ) + (N PRV x EF P

R V

) (Eq. 1)

where:

LR Operating = L eak rate from a compressor unit in “Operating” mode (scfh CH 4 )

N

CS

- Operating = N umber of compressor seals on the “Operating” unit

EF CS

— Operating = E mission factor for compressor seals on “Operating” compressors ( scfh CH 4 /seal)

N

BDV = N umber of blow down valves on the “Operating” unit

EF BDV = E m ission factor for blow down valves ( scfh CH 4 /blow down valve)

N

PRV = N umber of pressure relief valves on the “Operating” unit

EF PRV = E mission factor for pressure relief valves ( scfh CH 4 /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 sam e 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 = (N CS

- Standby Pressurized x EF CS

— Standby Pressurized ) + (N BDV x EF BDV ) + (N PRV x EF PRV ) (Eq. 2)

where:

LR Standby Pressurized = L eak rate from a compressor unit in “Standby Pressurized” mode

N

CS

- Standby Pressurized = N umber of compressor seals on the “Standby Pressurized” unit

EF CS

—

Pressurized = E mission factor for compressor seals on “Standby Pressurized” compressors

N

BDV = N umber of blow down valves on the “Standby Pressurized” unit

EF BDV = E mission factor for blow down valves

N

PRV = N umber of pressure relief valves on the “Standby Pressurized” unit

EF PRV = E mission 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

w ill 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 calcu lated pursuant to Equation 3:

LR Not Operating

-- Depressurized = N Unit Isolation Valve Pairs x EF Unit Isolation Valve Pairs (Eq. 3)

where:

LR Not Operating

-- Depressurized = L eak rate from a compressor unit in “Not Operating

– Depressurized” mode

N Unit Isolation Valve Pairs = Number of unit isolation valve pairs

EF Unit Isolation Valve Pairs = E mission factor for unit isolation valve pairs

.

The unit isolation val ves 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 transmissio n 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 mode s

– “Operating”, “Standby Pre ssurized”

, “Not Operating

— Depressurized” ) and the leak rate in two of the three modes per Equation 4a or 4b:

LR Annual = (α Operating × LR Operating ) + (α Standby Pressurized. × LR Standby Pressurized )

. (Eq. 4a) or

LR Annual = (α Operating × LR Operating ) + (α Not Operating

-- Depressurized × LR Not Operating

— Depressurized ) (Eq. 4b)

where:

LR Annual = A nnual leak rate from the compressor unit (scf)

α Operating = A mount of time compressor unit is “Operating”

α Standby Pressurized = A mount of time compressor unit is “Standby P ressurized ”

α Not Operating

-- Depressurized = A mount 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” ModePage | 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

N umber of PR V’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 DepressurizedPage | 8 Figure 3: Leakage fr om 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 V alve Pair Emission Factor x Number of Isolation Valve Pairs Compressor Seal Vent

Zero When Unit Depressurized



## Reciprocating Compressor Unit

– “Not Operating

-- Depressurized” ModePage | 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 l ine. 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 contribut ion of rod packing seal leakage while the compressor unit is operating, the hypothetical emission factor for “Operating” rod packing seals (99.0 scfh CH 4 ) is multiplied by the number of rod packing seals (4) and again multiplied by the activity factor (657 0 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 CH 4 /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 an d 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 CH 4 ) No. of Components Activity Factor (Hours Leaking /Y r) Annual

Emissions (Mcf CH 4 /Y r )

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 CH 4 /year) 4856Page | 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 CH 4 ) No. of Components Activity Factor (Hours Leaking / Y r ) Annual Emissions (Mcf CH 4 /Y r )

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 CH 4 /year) 6286Page | 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 devia tion, 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 I I

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 averag e cost impact 1 of $ 18 ,000 per pipeline transportation of natural gas s ystem facility and $24,000 per E&P facility is underestimated as shown in the following tables

.

T able 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 DifferencePage | 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 H 2 O Emissions

Hydrocarbon Liquids Dissolved CO 2

Produced H 2 O Dissolved CO 2 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

0.71 $ 106,313 $ 54,338 0.36 Basin @25k Field @25k

$ 189,000 $ 96,600

$ 2,100 $ 1,285,500 $ 649,500 8.57 4.33 $ 2,100Page | 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 H 2 O Emissions

Hydrocarbon Liquids Dissolved CO 2

Produced H 2 O Dissolved CO 2 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 4.33 $ 1,285,500 $ - 8.57 $ 649,500 $ - Emission Source Basin @25k Field @25k

$ 100,406 $ 189,000 0.67 $ 51,319 $ 96,600 0.34Page | 16 T able 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 H 2 O Emissions

Hydrocarbon Liquids Dissolved CO 2

Produced H 2 O Dissolved CO 2 General Costs (per field basis) 60 15 4,285 2,165 Estimated Source Count

Emission Source

315 161Page | 17 T able s A

- 5 : B asis For Adjustments to EPA Costs for Onshore Processing PlantsPage | 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 CostPage | 19 T ables A

- 6 : B asis 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 $55.20Page | 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 CostPage | 21 T ables A

- 7: B asis 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 $55.20Page | 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 FacilityPage | 23 T ables A

- 8: B asis 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 CostPage | 24 APPENDIX I II

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, S ection 114(a)(1) of the CAA. 75 Fed. Reg. 18608, 18610

- 11 (Apr. 10, 2009).

As EPA note s in the administrative record for the MRR rule it finaliz ed last year

, however, and as it states again in the current proposal, EPA faced a choice of proceeding under S ection 114 or under the Consolidated Appropriations Act

. Id . at 18610. A s EPA recognized in last year’s administrative record, however, “[b]y

p roceeding 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

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- 0056.2.) Possibly i n 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 S ection 114 of the CAA.

El Paso respectfu l ly submits that, by relying on S ection 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 limite d 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 prom ulgate the proposed rule under S ection 114, and these reservations are well founded. (See Doc. No. EPA

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- 0056.2.) Section 114 provides EPA with the authority to seek information “for the purpose of developing or assisti ng in the development of any implementation plan under S ection 7410 [. . .], any standard of performance under S ection 7411 of this tit le,

an emission standard under S ection 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, S ection 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 1 12 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 me t. 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.” CO 2 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 CO 2 is an “air pollutant,” EPA has not yet determined that CO 2 is a “pollutant subject to the Act.” Until EPA makes a final endangerment finding and a control requirement is established under the Act, CO 2 is not a “pollutant subject to the Act” and thereby n ot a “pollutant subject to the Chapter.” Nor can EPA rely on its authority to do studies andPage | 25 investigations under S ection 103 of the CAA to bootstrap into authority under S ection 114 for the proposed

rule. Section 103 does not mention the words “monitori ng” 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 o f particular classes of things, the general words are most naturally construed as applying only to things of the same gene ral

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 shou ld not, ther efore, be understood to expand S ection 114 to authorize monitoring and reporting on pollutants not yet considered “pollutants subject to the Act.”

EPA’s expansive int erpretation of S ection 114 would, in addition, obviate the need for many exp ress 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 CO 2 on certain electric genera ting 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 S ection 103), it wo uld have been unn ecessary for Congress

to enact S ection 821 to establish ongoing CO 2 monitoring and reporting requirements for power generating units, not to mention the monitoring requirements in S ection 112, Title IV, and Title VI of the CAA, among

other s. 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 statut e 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 interpre tation of S ection 114 would render many other sections of the CAA surplusage.

Finally, EP A’s proposed, expansive use of S ection 114 runs counter to its longstanding use of this section in the past. EPA’s us e of S ection 114 in the past has properly been li mited 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 S ection 114 to authorize the proposed monitoring and reporting rule is inconsistent with its longstanding prior use of this section. If challenged, therefore, t he 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 ab out its authority to interpret S ection 114 as broadly as the rule proposes, as reflected in the administrative record for the proposed rule. (See Doc. No. EPA

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- 0056.2.) EPA’s reservations about its authority to promulgate the proposed ru le under S ection 114 are well

founded. For the reasons discussed ab ove, among others, the proposed expansion o f the agency’s authority

under S ection 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 lim ited 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 Appro priations 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 lan guage 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

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- 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 Approp riations 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’ As s’n v. Skinner, 934 F.2d 1096 (9 th 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 report ing 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 Manageme nt 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 alre ady 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 p rinciple 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 Con solidated 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 autho rity 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

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- 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

- CI O 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

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- 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.