Attachment L

Leaks

Environmental Defense Fund

Ramón Alvarez, Robert Harriss, David Lyon
Oil and Natural Gas Sector Leaks 

Peer Review Responses of Environmental Defense Fund

June 16, 2014 

I. EXECUTIVE SUMMARY

• Leaks are a critical source of methane and other pollutants. We recommend leaks be 

treated as a very high priority as EPA evaluates further steps based on these White 

Papers. It is well-established that unintentional emissions of methane and VOCs from the 

oil and gas industry account for a substantial portion of overall emissions. Moreover, 

recent and ongoing scientific examination - conducted across geographies and value 

chain segments, and with diverse methodologies - reinforces that leaks are widespread 

and indicates they are even more of a problem than previously understood. Robust action 

on leaks should be a foundational element of any concerted approach to reduce methane 

emissions from the oil and gas industry. 

• Leaks tend to be concentrated within a limited subset of “gross emitter” facilities 

and components. Many studies have demonstrated that there is a highly skewed 

distribution of leaks. This concentration of leaks within a small proportion of sources has 

been observed both among groups of components within a site as well as among groups 

of entire facilities. This “gross emitter” characteristic of leaks is highly policy relevant, 

because it implies that comprehensive efforts to scan sites and identify and mitigate gross 

emitters through well-designed leak detection and repair (LDAR) programs can yield 

substantial benefits. 

• Comprehensive LDAR has broad-based benefits and can help reduce emissions 

from sources addressed in other White Papers. Although all five emission source 

categories EPA selected for analysis in its Oil and Natural Gas Sector Leaks White 

Paper1

 are important, leaks are unique in that they arise from not only traditional 

“equipment leaks” (e.g., valves, flanges), but also sources such as malfunctioning or 

poorly maintained compressors, pneumatic devices, storage vessels, and other equipment. 

Comprehensive or “holistic” LDAR programs that encompass entire facilities can help 

identify and resolve all such sources of unintentional emissions, and not just the 

traditional leaks that are commonly the focus of regulatory LDAR programs. We urge 

EPA to evaluate the cross-cutting nature of leaks, and the related, broad-based benefits of 

instituting holistic approaches to LDAR. 

• Cost-effective approaches for holistic LDAR are available today, and are 

continuously improving. Optical gas imaging (OGI) cameras have rapidly advanced to 

the forefront of leak detection technology, primarily because of the speed with which 

 

1

 EPA, Report for Oil and Natural Gas Sector Leaks (April 2014) [hereinafter “White Paper”], available at 

http://www.epa.gov/airquality/oilandgas/pdfs/20140415leaks.pdf 
ENVIRONMENTAL DEFENSE FUND • JUNE 16, 2014 

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these technologies can detect large leaks. Although OGI cameras do not currently 

quantify leaks, detection is of primary importance since most leaks are cost effective to 

repair once detected. This is widely regarded as a state of the art approach that enables 

effective and highly efficient detection of leaks. As a result, the use of OGI-based LDAR 

programs on a voluntary basis is now common among leading operators. OGI is also 

recognized as a permissible leak detection technology in several state-level regulatory 

programs as well as EPA’s Greenhouse Gas Reporting Program (GHGRP), Subpart W. 

At the same time, new technologies are emerging to enable near-continuous monitoring 

of facility-wide emissions, creating future potential for even more cost-effective and 

reliable identification of gross emitters. 

II. QUANTIFYING THE PROBLEM OF METHANE AND VOC LEAKS 

The White Paper correctly identifies most of the leading studies on the scale of leaks 

from oil and gas facilities. The reviewed literature indicates that leaks are not only a ubiquitous 

source of methane and other harmful pollutants, but may be the single largest emission category 

in the oil and gas sector. As the White Paper notes, EPA’s latest Annual Inventory estimates that 

potential emissions from certain leaks within the natural gas production, processing, and 

transmission segments amounted to approximately 481,000 metric tons of methane in 2012.2 

Leaks from metering and regulating facilities in local distribution systems – many of which can 

be remediated using LDAR approaches comparable to those used in upstream facilities – were 

estimated to contribute an additional 491,000 metric tons of methane.3 And as ICF’s Cost Curve 

Report notes, fugitive emissions from compressors are a further very large source, projected to 

reach over 1 million metric tons of methane in 2018.

4

 

Taking together all sources of fugitive emissions from above-ground components in the 

natural gas supply chain, ICF found that leaks are the largest emissions category in the oil and 

gas segment. ICF estimated that, in 2018, leak emissions from these sources will reach nearly 

2.3 million metric tons of methane, or 30% of all emissions from the oil and gas sector. 5 For this 

reason, minimizing or avoiding leaks from both new and existing sources is indispensable for 

reducing overall emissions from the oil and gas sector. Below, we critically evaluate the 

references cited in the White Paper, with particular focus on distributional characteristics of leaks 

that have significant implications for control strategies and policy responses. 

 

2

 White Paper at 19, 22. 

3

 EPA, Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2012, EPA 430-R-14-003 (April 2014), 

available at http://www.epa.gov/climatechange/ghgemissions/usinventoryreport/archive.html (“Annual Inventory”).

4

 ICF International, Economic Analysis of Methane Emission Reduction Opportunities in the U.S. Onshore Oil and 

Natural Gas Industries B-6 (March 2014) [hereinafter “ICF Cost Curve Report”], available at 

http://www.edf.org/sites/default/files/methane_ cost_curve_report.pdf. [the synthesis paper referecnes 

5

 Id. at 3-9. 
ENVIRONMENTAL DEFENSE FUND • JUNE 16, 2014 

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A. Holistic Understanding of Leaks and LDAR 

The White Paper well summarizes previous research on the scale of equipment leaks, and 

discusses most of the major recent studies and reports that inform our understanding of this issue. 

However, the White Paper does not provide an integrated synthesis of the lessons from this 

literature. Moreover, many of the studies presented focus on the overall scale of leaks. 

Although an understanding of aggregate emissions at the national level is valuable to 

understanding the urgency of addressing leaks, effective policy responses to leaks require a more 

granular understanding of the specific sources, causes, and characteristics of the emissions. 

One limitation of the White Paper is that it assesses emissions from equipment leaks in 

isolation from other emissions sources at the same facilities. This lens is unduly narrow, since 

LDAR to minimize emissions from equipment leaks can also be applied to controlling emissions 

from high-emitting pneumatic controllers and compressor seals, poorly maintained storage 

vessels, and other sources that are not always included in conventional LDAR programs.6

 In 

evaluating further action on leaks, EPA should broaden its understanding of this emission 

category to broadly encompass all unintentional emissions from oil and gas facilities, including: 

(1) equipment that is designed or intended to operate without emissions; or (2) sources with 

excess emissions beyond the level or range associated with well-functioning, routine operation. 

This expanded concept of leaks covers all emission sources which advanced LDAR programs are 

capable of addressing. 

For this White Paper to fully evaluate the effectiveness of LDAR programs, it should 

place greater focus on the total emissions from individual sites within each of the industry 

segments, encompassing the broader definition of leaks described above. Although LDAR is not 

a panacea for oil and gas emissions, it is a vital component of any reasonably comprehensive 

emission minimization strategy. Appreciating and achieving the full value of LDAR requires an 

informed view of its utility in reducing a wide breadth of emission sources. 

Given that a complete evaluation of an LDAR strategy must consider the entirety of 

emissions at sites where an emission survey is conducted - not just traditional equipment leaks - 

we believe EPA should give great weight to available field measurement data that characterize a 

full range of oil and gas site emissions. These studies include the Clearstone I and II reports on 

processing plant emissions; the Carbon Limits report on fugitive emissions at well sites, 

compressor stations, tank batteries, and processing plants; the Allen et al. study; and the Fort 

Worth study,7 which included comprehensive measurements of compressor, tank, and well pad 

fugitives. 

 

6

 Subpart VVa of EPA’s NSPS regulations, for example, requires LDAR for pumps, compressors, valves, 

connectors, and pressure relief devices. 40 CFR §§ 60.482-1a – 60.482-8a. LDAR is optional for compressor seal 

emissions, and does not appear to be required for storage vessels, pneumatic controllers, or other equipment under 

Subpart VVa. 

7

 ERG and Sage Environmental Consulting, LP, City of Fort Worth Natural Gas Air Quality Study, Final Report. 

(July 13, 2011) [hereinafter “Fort Worth Study”], available at

http://fortworthtexas.gov/gaswells/default.aspx?id=87074. 
ENVIRONMENTAL DEFENSE FUND • JUNE 16, 2014 

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B. Distribution of Leaks 

A major conclusion that emerges from evaluating emissions data at the site level is that 

most of the emissions are concentrated at a small proportion of “gross emitter” facilities.8 The 

White Paper generally describes this phenomenon, citing to the Carbon Limits study and the 

Clearstone I and II studies, but does not provide a quantitative assessment. 

Both the City of Fort Worth Natural Gas Air Quality Study and Allen et al. provide 

extensive, site-wide emission data that confirms the presence of gross emitters and allows for a 

clear depiction of the distribution of leak emissions. Figure 1 below presents site-wide emissions 

for natural gas production facilities from both of these studies. 

Fig 1. Distribution of site-wide emissions at natural gas production sites in Allen et al.

(2013) and in the City of Fort Worth Natural Gas Air Quality Study (2011).

 

8

 Skewed distributions of emissions are widely observed in studies of other sources in the oil and gas sector, 

including compressors and pneumatic devices. This phenomenon is described in our peer review comments on the 

White Papers evaluating these sources. 
ENVIRONMENTAL DEFENSE FUND • JUNE 16, 2014 

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In these studies, the highest 20% of emitting sites account for 60-80% of total emissions 

from all sites; the lowest 50% of sites account for only 3-10% of total emissions. Although these 

studies did not provide a definitive explanation for this distribution, these results – and other 

studies finding that leak emissions are highly concentrated — suggest that an effective emission 

reduction strategy is to frequently conduct leak surveys to identify the highest emitting sites and 

address sources at those sites. 

C. Characterization of Studies and Data Sources Quantifying 

Emissions (Question 1) 

The White Paper generally does a good job of summarizing previous work, but does not 

provide an effective synthesis or critical comparison of the recent studies on leak emissions. As 

EPA evaluates further action in this area, we recommend that EPA compare the results from each 

study using a common metric (in addition to whatever units the referenced study uses, should 

there be a difference). Below, we offer detailed comments on the summaries of leak studies that 

are presented in section 2 of the White Paper. 

1. White Paper Section 2.1 

The White Paper notes that EPA’s correlation equations for petroleum refineries, which 

allow for component emission rates to be estimated based on organic compound concentrations 

measured using Method 21, are designed to estimate total organic compound (TOC) emissions. 

For oil and gas sector facilities, TOC is of limited utility unless gas composition data is available 

to estimate the fraction of methane, VOCs, and other pollutants in the emissions stream. 

 2. White Paper Section 2.2 

In describing the use of GRI data to extrapolate national emissions from leaks, the White 

Paper appears to misstate the method used. The White Paper notes that facility-level emissions 

were extrapolated to a national level using a count of production facilities, but in fact this method 

was used for facilities in all segments and not just production. 

 3. White Paper Section 2.5 

The summary omits the Allen study’s national estimate of emissions from equipment 

leaks in the natural gas production segment, which is 15.1 bcf/yr or 291,000 metric tons. This 

value is 38 to 69% higher than comparable net emissions in the EPA GHG inventory.9

 Note that 

this estimate does not include leaks from compressors and other equipment not directly measured 

in the Allen study. 

The White Paper also overlooks that the data from the four sites with separators and other 

equipment did not include wells and was not included in the averaging - the total data set for 

equipment leaks was 146 sites with a total of 478 wells. 

 

9

 David T. Allen et al., Measurements of methane emissions at natural gas production sites in the United States, 110 

Proceedings of the National Academy of Sciences 17768, 17771 (Oct. 29, 2013).
ENVIRONMENTAL DEFENSE FUND • JUNE 16, 2014 

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The summary correctly states that the Allen study values for average leak emissions are 

comparable to the average values for potential emissions for certain equipment types. The 

implications of this result are not fully described in the White Paper. Specifically, the Allen 

study values are more usefully compared to net or “actual” emission factors, in light of EPA's 

approach of applying regulatory and voluntary reductions to the potential emissions in order to 

arrive at net emissions. The Allen study at Section S2.2 concludes that net emissions for 

comparable equipment types in the Annual Inventory are "roughly half to two-thirds of the 

emissions measured in this work" (the differing values depend on how compressors are 

included). In other words, results from the study suggest that the EPA Annual Inventory 

underestimates actual emissions for certain equipment leaks. 

The summary should indicate that the Allen study also reports measurements from 124 

tank leaks that were detected with an IR camera. These results appear in the study database 

posted on the University of Texas study website. However, the results are not discussed in the 

published paper because not all tank emissions were quantified. 

 4. White Paper Section 2.6 

Numerous pneumatic controllers and tanks are included in the "other" emission category 

reported in this study. Because emissions from these sources have a distinct profile from other 

fugitive emission sources, it is important to distinguish these sources when utilizing the Fort 

Worth data. 

An aspect of this study that is not discussed is the distribution of emissions from the 

sampled population of well sites, which is presented in Figure 1 above. Alvarez et al. (2012) 

report that 10% of the surveyed well sites in the City of Fort Worth Study accounted for nearly 

70% of total emissions.10 

 5. White Paper Section 2.10 

The third paragraph's characterization of the ICF report's treatment of well site emissions 

is incorrect. ICF does not estimate total leak emissions from well sites, only wellheads. ICF at 

section B.3.1.2 developed its own wellhead fugitive emission factor by drawing from data in the 

Allen study. Specifically, ICF used reported measurements from the Allen study for “any 

identifiable well head emissions (i.e., emissions from the well itself, not the associated 

equipment).” ICF then derived an overall per well emission factor from the Allen study by 

aggregating the measured emissions and dividing by the well count. 

The next paragraph in the summary correctly describes how other equipment leaks were 

handled. ICF used 1996 GRI values for Heaters, Separators, Dehydrators, and Meters/Piping; 

the data from the Allen study were not used for these sources.

11

 

 

10 Ramón Álvarez et al., Greater focus needed on methane leakage from natural gas infrastructure, 109 Proceedings 

of the National Academy of Sciences 6435, 6437 (2012). 

11 ICF Cost Curve Report, supra note 4, at section B-4. 
ENVIRONMENTAL DEFENSE FUND • JUNE 16, 2014 

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 6. White Paper Section 2.12 

The White Paper correctly notes that the Clearstone II study observed a highly skewed 

distribution of emissions, which is an important result and is consistent with the other data 

described above. 

D. Applicability of Estimation Methods (Question 3) 

The procedures for quantifying leaks that are presented in the White Paper are generally 

applicable to oil and gas facilities at various stages of the value chain. However, there are some 

practical considerations that may limit the applicability of direct emission measurement in 

certain instances. In particular, the use of Hi-Flow to quantify emissions from leaks at 

production sites with rich gas (high VOC content) could be affected by the VOC content in gas. 

This effect was noted in Modrak et al. for certain measurements of tank emissions (see Figure 3 

therein).12 In addition, some sources may not be accessible for direct measurement with HiFlow 

without a lift or scaffolding. This was a major reason for the exclusion of tank measurements in 

the Allen study: elevated tank vents were not reachable. 

E. Ongoing or Planned Studies That Will Provide Supplemental 

Information (Question 4) 

Colorado State University and Carnegie Mellon University are leading two studies 

designed to characterize methane emissions from specific natural gas industry segments: one 

focuses on transmission and storage, and the other on gathering and processing. Both are part of 

the research series catalyzed by EDF and are being done in partnership with natural gas 

operators. Both studies will report emission measurements taken at representative facilities and 

are on track to submit papers for publication in peer-reviewed scientific journals by late summer 

2014. 

Another project sponsored by EDF that focuses on emissions from oil and gas operations 

in the Barnett Shale will result in facility-level emission data for a modest sample of production 

well pads, and a more limited number of midstream and transmission facilities in the area. For 

well pads, preliminary data from this project are consistent with the results of the City of Worth 

study, showing that a relatively small proportion of well sites produce a large share of the total 

emissions from the sampled population. Papers summarizing the results of this work should be 

submitted for publication in peer-reviewed scientific journals by late 2014. 

F. Factors Driving Variable Emissions (Question 5) 

As yet, we have not been able to identify specific facility characteristics or operating 

parameters that are associated with high leak emissions (one exception might be for equipment in 

compressor service vs non-compressor service due to the vibrational/mechanical stresses places 

 

12 Modrak, Mark T., et al. 2012. Understanding Direct Emissions Measurement Approaches for Upstream Oil and 

Gas Production Operations. Air and Waste Management Association 105th Annual Conference and Exhibition, 

June 19-22, 2012 in San Antonio, Texas. 
ENVIRONMENTAL DEFENSE FUND • JUNE 16, 2014 

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on the equipment in compressor service).13 Rather, gross emitters appear to be due to random

occurrences of low-probability but high-emission conditions, such as maintenance issues and 

serious malfunctions. The apparently random nature of high leak emissions underscores the 

utility of frequent LDAR programs conducted expansively at oil and gas facilities at each stage 

of the value chain. 

III. UNDERSTANDING LANDSCAPE OF DETECTION TECHNOLOGY AND ITS 

APPLICATIONS 

 

The White Paper effectively identifies and describes the main categories of leak detection 

technologies. In this short Section, we: (i) briefly summarize the advantages and disadvantages 

of OGI, cavity ring-down spectrometers, and handheld organic vapor analyzers and toxic vapor 

analyzers (question 7) (ii) comment on the prevalence of technology use at upstream facilities 

(question 8), and (iii) comment on the state of innovation in leak detection technologies 

(question 13). 

A. Advantages and Disadvantages of Major Leak Detection 

Technologies 

 

To supplement the discussion in the White Paper, we have provided in Table 1 below a 

qualitative assessment of the advantages and disadvantages of the major leak detection 

technologies evaluated in the White Paper. As Table 1 shows, each technology carries its own 

balance of capital costs, labor requirements, sensitivity, and quantification capability. 

Table 1. Pros and Cons of OGI, Portable Analyzers, and Other Technologies. 

Pros Cons 

Optical Gas 

Imaging 

• Proven technology already 

seeing extensive voluntary 

industry use 

• Enables rapid/efficient 

assessments which lowers 

labor intensity and cost 

• Capital cost can be spread 

over many facilities 

• Suitability for site-level 

assessments, including 

physically inaccessible 

components 

• Relatively high capital cost 

• Lack of quantification 

Portable • Relatively low capital cost • Relatively time-intensive 

 

13 See Fort Worth Study, supra note 6, at 3-34 (noting that total organic compound emissions from well pads with 

compressors were nearly 50% higher than at well pads without compressors, counting only sources measured with a 

HiFlow sampler). 
ENVIRONMENTAL DEFENSE FUND • JUNE 16, 2014 

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Analyzer • Long track record of 

regulatory use through 

Method 21 

assessments 

• Labor intensive – high 

operating cost 

• Cannot analyze emissions at 

physically inaccessible 

components 

Laser 

absorption 

spectroscopy 

• Capable of high accuracy 

and precision 

• Minimal track record for 

corporate LDAR 

• Generally high capital cost 

Acoustic 

methods 

• Questionable accuracy and 

reliability 

• Capital cost believed to be high 

 In addition to the characteristics highlighted in Table 1, certain challenges – for example 

dealing with adverse precipitation or wind conditions – are common to all of the individual 

technologies above. 

B. Penetration Rate 

 Although EDF agrees with the White Paper that there is little quantitative data on the 

prevalence of OGI cameras in the oil and gas industry, our interactions with industry operators 

and other experts confirms that OGI technology has clearly emerged as the technology of choice 

for voluntary industry use. For example, at an invitation-only technology workshop EDF held in 

2013, there was widespread consensus among the four leading industry players – who span 

production, gathering, and processing – that OGI provides a reliable and proven means of 

detecting leaks. Moreover, during the industry dialogue phase of the ICF report preparation, OGI 

was uniformly validated as the best available practical means for efficient detection of leaks. 

Further, publicly available information indicates that leading companies such as Shell, Anadarko 

Petroleum Corporation, and Noble Energy are voluntarily utilizing infrared cameras for leak 

detection and repair purposes. The commercial traction achieved by OGI cameras is the strongest 

testament to their capability for reliable and efficient leak detection. Increasing voluntary uptake 

– in the competitive and cost conscious oil and gas industry – is highly indicative of 

effectiveness. 

 In parallel with rising voluntary use of OGI, OGI cameras are also increasingly being 

integrated into regulatory programs. Three states – Colorado, Ohio, and Wyoming – have 

recently adopted LDAR requirements for oil and gas facilities that allow the use of OGI cameras 

as a means of compliance.14 Since 2011, Subpart W of EPA’s Greenhouse Gas Reporting 

Program has also allowed the use of OGI cameras to detect leaking components at above-ground 

 

14 Co. Dep’t of Pub. Health & Env’t Reg. No. 7 (5 CCR 1001-9), Unofficial Draft (Feb. 23, 2014) § XVII.F.; Ohio 

Envtl. Prot. Agency, General Permit 12.1(C)(5)(c)(2), 12.2(C)(5)(c)(2); Wyo. Dep’t of Envtl. Quality, Oil and Gas 

Production Facilities: Chapter 6 Section 2 Permitting Guidance (June 1997, Revised Sept. 2013). 
ENVIRONMENTAL DEFENSE FUND • JUNE 16, 2014 

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facilities in natural gas processing, transmission, storage, and distribution, as well as LNG 

import/export facilities.15 

C. Innovation in Leak Detection 

 Although OGI and other leak detection technologies are currently feasible and costeffective for a wide variety of oil and gas facilities, significant innovation continues to occur in 

the area of leak detection technology. As public and industry consciousness of fugitive 

emissions rises, and new policies have emerged to address leak emissions, demand is growing 

for ever more effective and economical monitoring approaches. This demand signal is increasing 

at the same time that on the technology supply side, we see a growth in cost-effective sensing 

technology, and more interest and capability in mining “big data” to generate actionable 

information to improve environmental and business performance. 

 Since the publication of the White Paper, The Department of Energy’s ARPA-E program 

announced its MONITOR initiative to catalyze development of low cost, efficiently deployed 

methane sensing technology. This project is complementary to EDF’s Methane Detectors 

Challenge, which EPA noted in the White Paper. 

 Both projects are synergistic in helping to spur new technological solutions to 

reduce methane emissions from the production and transportation of oil and gas. EDF’s 

competition targets relatively mature technologies that can be deployed in the next two years to 

detect larger leaks on a continuous basis. In contrast, ARPA-E’s program targets a wider range 

of early-stage technologies that – with significant R&D — could become disruptive technologies 

capable of detecting a broad range of leak sizes in the next ten years. These projects complement 

each other in that both are expected to stimulate technology demonstration and development, 

build market demand for new detection approaches, and ultimately catalyze major emission 

reductions that will benefit the environment, public health and maximize resource utilization. 

Table 2 explains how the EDF and ARPA-E programs compare.

Table 2. Comparison of ARPA-E and EDF Methane Detection Initiatives. 

 EDF Methane Detectors Challenge ARPA-E MONITOR Program 

Industry 

applicability 

Focused on emissions from well pads 

and associated equipment, and 

compressors 

Focused on oil and gas systems from 

the wellhead to the end-user 

Technology 

stage 

Relatively mature technologies ready 

for testing in a controlled 

environment, and able to be deployed 

in industrial settings in the short run 

Early stage technologies requiring 

substantial time and resources for 

development to ensure reliable 

detection for transformational 

improvements 

 

15 EPA, Greenhouse Gas Reporting Program (GHGRP), Subpart W, available at

http://www.epa.gov/ghgreporting/reporters/subpart/w.html 
ENVIRONMENTAL DEFENSE FUND • JUNE 16, 2014 

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Scope of 

detection 

Limited to continuous detection 

technologies, that provide a 24/7 

approach to detecting leaks 

Open to continuous or 

periodic/mobile approaches to 

detecting emissions 

Leak size 

Focused on large leaks; initial basic 

requirements of 5 and 2.5 scfm for 

detection, with preference for adaptive 

technologies and potential to detect 

somewhat smaller leaks 

Focused on a wide range of 

emissions including small leaks; 

threshold of 0.1 scfm 

Information 

provided 

Notification of methane emissions, 

including rough indication of leak 

size; leak location not required 

Reasonably accurate quantification 

of methane emissions, in addition to 

leak location down to 1m precision 

Timeline 

Full proposals due June 17,2014; 

testing begins summer 2014; industry 

pilots expected in 2015 

Concept papers due June 13, 2014, 

Full application deadline TBD 

Funding type 

Independent testing paid for by EDF; 

industry pilot purchases expected; no 

development awards anticipated 

Up to $30M provided for 

development of the technology, in 

increments between $250,000 and 

$10M per awardee 

Market 

access 

Many of the participating companies 

intend to make pilot purchases and 

trial deployments of instruments that 

meet the specifications 

Not applicable 

Partnership EDF partnering with five leading oil 

and gas producers 

ARPA-E partnering directly with 

innovators to help them develop 

their technologies; no industry 

partnership planned at this time 

 As innovation continues in this space, it is likely that different technologies or approaches 

will emerge to address unique challenges in each segment of the natural gas supply chain. Midstream companies, for example, are testing airborne remote sensing technologies. Local 

distribution companies are exploring technologies that will measure, for the first time, 

quantitative leak rates from below ground leaks. 

 Nevertheless, the sheer number of new technologies that are in development bodes well 

for significant cross-cutting improvements in the efficacy and cost of leak detection. As an 

illustrative list, EDF incorporates here the most promising technology development areas that 

ARPA-E has identified: 
ENVIRONMENTAL DEFENSE FUND • JUNE 16, 2014 

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• Reduced-cost tunable diode laser systems that incorporate either an internal absorption 

path or an external absorption path; 

• Reduced-cost long-path spectroscopic approaches which are configured to provide 

sensing along one side or potentially around the entire perimeter of a site of interest; 

• Hyperspectral approaches with an ambient thermal radiation infrared source; 

• Absorption approaches in which the sun or sky provide the reference source; 

• Low-cost approaches to mid-infrared (IR) detectors, particularly uncooled detectors; 

• Reduced cost and/or increased resolution methane imaging systems, particularly with 

non-cryogenic detectors; 

• Single-point sensors or imaging systems using plasmonic detectors, with particular 

interest in uncooled plasmonic detectors; 

• LIDAR or laser backscatter approaches; 

• Mobile sensing from dedicated and non-dedicated ground vehicles and aerial vehicles; 

• Low-cost approaches to mid-IR lasers, including quantum cascade lasers (QCLs), 

intersub-band gap lasers (ISBs), vertical cavity surface emission lasers (VCSELs), or 

other novel/emerging concepts; 

• Advanced data analytics that aggregate localized methane measurement with wider area 

atmospheric and dispersion models in order to estimate regional flux rates, including, but 

not limited to: 1) GIS integration, 2) reinforcement learning, 3) inversion modeling, 4) 

micro-climate modeling, and 5) site flux apportionment. 

For EPA, continued innovation in leak detection technology has two major implications. 

First, as with other new pollution control technologies, it is likely that relatively recent 

innovations such as OGI cameras will continue to decline in cost and improve in performance as 

their production and use increases. Second, it is important that policy frameworks to minimize 

leaks be flexible enough to encourage and recognize future developments in leak detection 

technology, and not erect undue barriers to using new and better technologies as they are 

developed. 

IV. EVALUATING DETECTION STRATEGIES AND ECONOMICS 

This Part builds from the discussion of leak detection technologies in Part III of our 

comments by addressing strategies to reduce emissions and the cost and effectiveness of those 

strategies. Detecting leaks is, of course, a critical piece of a strategy to reduce leaking emissions, 

but, as the White Paper notes, it is only part of a strategy that must also include repair. 

Moreover, within each of these two components – leak detection and repair – there are several 

factors that influence both the effectiveness and the cost of different leak detection and repair 

strategies. The White Paper focuses specifically on the impacts of technology, but the scope of 

detection and repair practices and the frequency or timing of those practices are also important 

determinants of effectiveness and cost. Table 3 below sets forth illustrative options in each of 

these areas that affect both the cost and effectiveness of a LDAR program. 
ENVIRONMENTAL DEFENSE FUND • JUNE 16, 2014 

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Table 3. Factors Influencing Effectiveness and Cost of LDAR Programs.16

Technology Scope Frequency/Timing 

Leak Detection Examples: Method 21; 

IR Cameras; or Mobile 

CRDS 

Examples: Componentspecific; Site-wide Examples: Monthly; 

Quarterly 

Repair Examples: Standard 

repair; use low-leak 

technology 

Examples: All leaking 

components; emission 

threshold; or economic 

threshold 

Examples: Repair after 

5 days 

ICF’s cost curve report includes a rigorous assessment of LDAR programs that 

underscores their wide applicability, efficacy in reducing emissions, and high degree of cost 

effectiveness. Table 4 excerpts the ICF report’s high level findings on LDAR opportunities 

across the supply chain (not including for the distribution segment). For this analysis, ICF 

assumed the use of quarterly LDAR utilizing OGI technology, applied to entire facilities. 

Consistent with analyses undertaken by EPA and Colorado, ICF assumed this technique would 

have a 60% control effectiveness. ICF found that LDAR would reduce emissions by over 50 

billion cubic feet per year, at a net annual cost of under $50 million. This equates to a more than 

10% reduction of total onshore projected methane emissions for 2018, at a net cost that is 

roughly 0.01% of the oil and gas industry’s annual capital expenditure. 

Table 4. ICF Findings Regarding Costs and Effectiveness of Comprehensive LDAR. 

Value Chain Segment Total annual cost ($Million) Reduction achievable (Bcf) 

Well Fugitives 43.9 12.5

Gathering and Boosting 

Stations 5 3.3

Compressor Stations 

(Storage) -4.5 1.5

Compressor Stations 

(Transmission) 7.7 2.8

Reciprocating 

Compressor Fugitives -10.5 32.3

Total 41.6 52.4

Below, we address several aspects of leak detection efficacy and cost-effectiveness in 

more detail. Part IV.A explores technology considerations relevant to the effectiveness of leak 

 

16 It is believed that an additional factor influencing effectiveness of LDAR is proper training and incenting of 

personnel carrying out the in-field activities, be they employees or contractors. We encourage EPA to take account 

of the human factors that may influence environmental performance. 
ENVIRONMENTAL DEFENSE FUND • JUNE 16, 2014 

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detection and repair strategies. In particular, we concur with the White Paper’s conclusion that 

IR cameras and mobile monitoring can reduce leak detection costs while effectively detecting 

major leaks. On the repair side, we present evidence, not included in the White Paper, that 

repairing leaks with low-leak technology can further reduce emissions without markedly 

increasing costs. Part IV.B addresses the scope of leak detection surveys and repair efforts, 

concluding that performing site-wide surveys (including components like pneumatics and 

compressors) is important for optimizing emissions reductions and has minimal cost impacts 

given economies of scale. Part IV.C discusses frequency of surveys, and Part IV.D analyzes 

two-step LDAR, a specific strategy on which the White Paper requests comment. 

A. Technologies: Implications for Cost / Effectiveness 

EPA’s White Paper presents capital costs associated with different leak detection 

technologies, and we agree that these costs seem appropriate. Importantly, however, leak 

detection devices can be used to search for leaks at multiple sites, and so attributing the full cost 

of detection equipment to a single site grossly overstates costs. In its Oil Well Completion White 

Paper, EPA recognizes that flare technology can be used at multiple well-sites and that costs 

should be adjusted accordingly.17 We encourage EPA to similarly adjust capital costs for leak 

detection equipment (and where appropriate, other initial or start-up costs) to reflect that this 

equipment can be deployed at multiple well sites.18 

This point is relevant to a broader consideration regarding both cost and effectiveness – 

that both should be assessed in terms of the leak detection and repair strategy as a whole. 

Technology choice and its impacts on survey speed are a larger cost driver than capital costs for 

overall LDAR strategies, and below, we assess opportunities to reduce costs with IR cameras and 

whether those devices materially impact survey effectiveness. We also assess the efficacy of 

low-leak repair technologies. 

1. Leak Detection – Speed & Effectiveness of IR Cameras 

Survey speed is an important driver of the overall cost of LDAR, and we believe that 

available technologies allow operators to survey facilities more quickly and with similar 

effectiveness to Method 21 using portable analyzers. The discussion below focuses on IR 

cameras (2-step LDAR is discussed separately) and the cost and effectiveness implications of 

this technology. 

 

17 EPA, Report for Oil and Natural Gas Sector Oil Well Completions and Associated Gas during Ongoing 

Production 32 (April 2014), available at http://www.epa.gov/airquality/oilandgas/pdfs/20140415completions.pdf. 

18 In past analyses of LDAR cost-effectiveness , EPA does not appear to have assumed that leak detection equipment 

costs or other start-up costs (such as the acquisition of data collection systems) could be shared among multiple 

sites. See EPA, Oil and Natural Gas Sector: Standards of Performance for Crude Oil and Natural Gas Production, 

Transmission, and Distribution, Background Supplemental Technical Support Document for the Final New Source 

Performance Standards at C-4 (2012). 
ENVIRONMENTAL DEFENSE FUND • JUNE 16, 2014 

15 

EPA’s White Paper notes that IR technology can reduce the time it takes to survey a 

facility for leaks and presents a number of estimates of survey time from different studies and 

literature.19

 

Table 5. White Paper Studies Identifying OGI Survey Speed. 

Study Survey Speed 

(components / hr) 

RTI (2012) 1,875 

ICF (2003) 2,100 

Although the White Paper asserts that these studies underestimate the amount of time 

required for OGI surveys,20 additional studies corroborate the estimates in Table 5 and, indeed, 

suggest they may even overstate the time needed to survey facilities. For instance, a 2007 

technical paper in the Journal of Air & Waste Management (“Robinson study”) found that an IR 

Camera was able to survey 27,000 components in a refinery during a 13 hour period (2,100 

components per hour).21 Moreover, the study authors noted that “[t]his monitoring does not 

represent a typical or anticipated maximum rate when using optical leak imaging as an 

alternative to Method 21” because “[s]ignificant time was spent collecting data and allowing 

participants to view the leaks.” ICF’s 2014 cost curve report also concludes that EPA’s projected 

screening times are potentially too long.22 Even assuming a longer screening time, IR cameras

provide an opportunity for dramatically faster sampling when compared to Method 21 (700 

components per day). 

While IR cameras can significantly improve screening time, it is critical that the 

technology screens leaks as effectively as Method 21 using an OVA / TVA. EPA’s White Paper 

discusses potential difficulties with IR screening (temperature, wind, etc.) that may make 

screening potentially less accurate using these devices.23 However, the quantitative comparisons 

that exist indicate that OGI is comparable to Method 21 in reliably detecting major leaks. The 

Robinson study, for example, found that an IR camera was able to “identify leaking components 

that were the source of 97% of the total mass emissions from leaks detected [using Method 

21].”24 

Further, the Fort Worth study data allows for a direct comparison of Method 21 and OGI 

effectiveness. This study measured emissions at 388 natural gas sites in the Barnett Shale 

 

19 See White Paper at 40. 

20 Id. 

21 Donald R. Robinson et al., Refinery Evaluation of Optical Imaging to Locate Fugitive Emissions, 57 JOURNAL OF 

THE AIR & WASTE MANAGEMENT ASSOCIATION 803-810 (2007). 

22 ICF Cost Curve Report, supra note 4 at 3-11. 

23 White Paper at 41. 

24 Robinson study at 803. 
ENVIRONMENTAL DEFENSE FUND • JUNE 16, 2014 

16 

region. Component leaks were surveyed with a combination of Method 21 and OGI, followed 

by direct measurements and modeling to quantify emissions. Method 21 identified 2,093 

components above a 500 ppm total hydrocarbon screening threshold that contributed 97% of 

total emissions, while OGI 1,330 identified components with visible emissions that contributed 

94% of total emissions. Components detected by Method 21 but not OGI tended to have small 

emissions with a minor contribution to total site emissions. In comparison, OGI detected large 

leaks at some components that were inaccessible for Method 21 screening. Therefore, OGI is as 

effective as Method 21 in detecting all but the smallest leaks and has the added benefit of 

surveying leaks that are inaccessible to Method 21 screening.25 

Accordingly, we believe that available evidence suggests LDAR using IR cameras is as 

effective as Method 21 but less costly due to the speed with which operators can survey sites 

using cameras. 

2. Repair – Low Leak Technologies 

Repair technologies can also achieve emissions reductions. EPA’s White Paper does not 

specifically address these technologies, but “low leak” or “leakless” valve packings, gaskets, and 

other equipment can be certified to operate with minimal fugitive emissions. Certain low-leak 

technologies, such as “Low-E” valves and valve packings, have been in use for over fifteen 

years, have been found to leak rarely and at minimal rates, and are available at a moderate cost 

premium of 10-35% relative to standard valves.26 Manufacturers of this equipment have begun 

issuing warranties assuring that the equipment will not emit fugitive emissions in concentrations 

greater than 100 ppm, and several standard industry test protocols are available for certifying 

low-leak equipment.27 As a result, over the last several years EPA has included provisions in 

consent decrees with petroleum refineries and chemical facilities that require replacement of 

leaking valves and valve packings with low-leak technology.28 In addition, EPA’s proposed 

Uniform Standards for equipment leaks would require that low leak technology be used to repair 

or replace valves and connectors for which a repair cannot be completed within the standard 15-

day deadline provided in the proposed rule.29 Accordingly, this low-leak replacement 

technology should be considered as a mitigation technology in EPA’s White Paper. 

B. Scope: Implications for Cost / Effectiveness 

1. Leak Detection – Site Surveys vs. Component Surveys 

As discussed in II.A., a holistic approach to LDAR that encompasses surveys of entire 

facilities can maximize the number of leaks found and fixed. By surveying the full site 

 

25 As an exhibit, we are providing a spreadsheet with the underlying data and calculations presented in this 

paragraph. 

26 Kosta Loukeris, Low Leak Valve and Valve Packing Technology (Low-E Valve), 4 (EPA, Aug. 16, 2011); See also 

Joseph Wilwerding, Fugitive Emissions From Valves: Update, Hydrocarbon Processing V-81, V-82 (June 2010) 

(indicating that costs for low-leak valve packings are “similar and sometimes less than costs for similar equipment.”) 

27 Loukeris, supra note 26, at 10. 

28 See Id. at 14 (listing seven consent decrees signed as of August 2011); James Drago, Legislating Leak Detection: 

How U.S. Regulations Are Impacting the Rest of the World, 18 FLOW CONTROL 11, 16-18 (Nov. 2012). 

29 77 FR 17,897 (Mar. 26, 2012). 
ENVIRONMENTAL DEFENSE FUND • JUNE 16, 2014 

17 

comprehensively, unexpected leak sources can be identified efficiently. Moreover, while a 

comprehensive approach optimizes emission reductions, it does not materially increase cost 

relative to a more limited and traditional LDAR program. Regardless of scope, operators incur 

certain fixed costs, such as equipment, personnel, and training, for establishing a LDAR 

program. Sampling the full range of potential leaking components – including pneumatics, 

storage tanks, and compressors – can uncover substantial additional leakage at minimal 

incremental operating costs, including those for additional employee time and any administrative 

costs for tagging and tracking components.30 

Indeed, recent evidence from companies, regulators, and independent studies suggest the 

importance of a comprehensive approach to LDAR. In a February, 2014, Natural Gas Star 

Technology Transfer Workshop, Southwestern Energy noted that primary LDAR targets 

included valves, connectors, and open-ended lines, while secondary targets included pneumatics, 

compressors, and storage tanks.31 Colorado’s rules include LDAR requirements applicable to 

well-sites, storage tanks, and compressors,32 and ICF’s 2014 Cost-Curve Report identifies both 

well-sites and compressors as significant opportunities to reduce fugitive emissions (concluding 

LDAR at reciprocating compressors actually has a net positive payback).33 The Carbon Limits 

Report confirms these findings and also concludes that LDAR programs may help to identify 

other malfunctioning devices like pneumatic controllers.34 

2. Repair – Cost of Detection vs. Repair (Question 11) 

The scope of repair (whether all leaks are repaired or only a subset) is likewise important 

to the cost / effectiveness of a LDAR program. EPA has requested comment on the cost of 

detecting a leak when compared to repairing a leak, and in particular, the conclusion that nearly 

all leaks are economical to repair once detected given the relatively modest costs of repair. We 

agree that repair costs are a small fraction of overall LDAR costs and an LDAR approach where 

all leaks are repaired has obvious advantages in terms of effectiveness but also has potential cost 

savings when compared to program focused on repair of only a subset of leaks (those that are 

above a certain threshold). 

The White Paper presents evidence that the vast majority of leaks are economical to 

repair once detected because repair costs are small and offset by gas savings. As a threshold 

matter, we note the relatively good agreement between the Carbon Limits Study and Clearstone 

II on the costs of repairing different types of components. As Carbon Limits notes, both median 

and average repair costs for many components fall below $100 – a small fraction of the cost of 

monitoring at the facility. Moreover, Carbon Limits, Clearstone I and Clearstone II present a 

 

30 Importantly, components such as pneumatic devices, storage tanks, and compressors are far more limited in 

number than valves, connectors, and other components monitored in typical LDAR programs. 

31 Southwestern Energy, EPA Natural Gas Star Production Workshop (Feb. 11th ,2014), available at

http://www.epa.gov/gasstar/documents/workshops/denver-2014/Southwestern_Energy.pdf 

32 5 COLO. CODE REGS. § 1001-9 XVII.F. 

33 ICF Cost Curve Report, supra note 3, at 4-3. 

34 Carbon Limits, Quantifying the Cost-effectiveness of Systematic Leak Detection and Repair Programs Using 

Infrared Cameras 5 (Mar. 2014), available at http://www.carbonlimits.no/PDF/Carbon_Limits_LDAR.pdf. 
ENVIRONMENTAL DEFENSE FUND • JUNE 16, 2014 

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strongly consistent picture of the percentage of leaks that are economical to repair 

(approximately 90%, 95%, and 96% respectively). The White Paper’s conclusion is robust. 

Repairing all leaks also has obvious benefits in terms of the effectiveness of an LDAR 

program. EPA’s White Paper describes these clearly,

35 and we do not have any additional 

comments. An approach focused on repairing all leaks, however, may have less obvious cost 

benefits when compared to approaches focused on threshold repair levels. In particular, 

repairing all leaks does not necessarily require that an operator quantify each found leak, which, 

for detection technologies like OGI that are not capable of quantification, has the potential of 

reducing overall costs associated with the LDAR strategy. Conversely, setting a threshold level 

of repair would require quantification in all instances and could lead to inefficiencies with 

fluctuating gas prices. The next section discusses the importance of quantification generally as 

part of an LDAR program. 

3. Repair – Importance of Quantification (Question 12) 

To assess the relative importance of leak detection and leak quantification, it is helpful to 

be clear on the objectives of the field exercise itself. For scientific studies, such as the “bottomup” studies conducted by EDF and others, the objective is to create a rigorous and accurate 

estimate of emission rates, based on direct measurement. For that objective, it is plain that 

detection alone would be insufficient, and quantification is required. The additional time and cost 

associated with full quantification is a necessary part of the scientific process. 

 An effective pollution control regulatory regime, however, differs from a scientific 

inquiry. For example, technology-based emission standards under the Clean Air Act must merely 

be designed to achieve emission reductions swiftly, effectively, and at reasonable cost, to achieve 

environmental and public health goals. In this context, leak detection should be the primary goal, 

since as a general matter, detection alone is both necessary and sufficient to enable repair. A 

blanket requirement of quantification on top of detection could add cost, and perversely could 

actually extend the duration of leaks to make time for quantification after detection and before 

correction. Neither current EPA regulations requiring LDAR at new gas processing plants,36 nor 

LDAR regulations adopted by various states, require quantification of leaks prior to repair. 

 Were EPA to consider future action that would entail quantification of leaks, the agency 

could consider a potential supporting role for limited quantification. For example, quantification 

could be required for a limited but statistically significant sample of leaks detected and fixed, 

both to enhance verification and potentially to enable more precise determinations of the benefits 

of LDAR.

C. Frequency: Implications for Cost / Effectiveness (Question 9) 

In addition to technology and scope, the frequency of leak detection activities and the 

speed with which repairs are carried out have implications for the cost and effectiveness of an 

LDAR program. Charge question 10 specifically requests comment on how frequency impacts 

cost and effectiveness in the context of voluntary industry LDAR programs. While we do not 

have evidence concerning voluntary industry efforts, several reports and regulatory support 

documents provide evidence of the impact of different monitoring frequencies on effectiveness. 

 

35 White Paper at XX (greater emissions reductions achieved through comprehensive repair). 

36 See generally 40 CFR Part 60, Subparts OOOO and VVa. 
ENVIRONMENTAL DEFENSE FUND • JUNE 16, 2014 

19 

The White Paper does not include this information and we believe that it is important to 

incorporate. In particular: 

• ICF Cost Curve (2014) – ICF cites both EPA and Colorado research indicating Annual 

Inspections reduce emissions by 40%; quarterly inspections by 60%; and monthly 

inspections by 80%.37

 

• Carbon Limits (2013) – Carbon limits likewise concluded that more frequent inspections 

result in greater emissions reductions. The database Carbon Limits used to perform the 

analysis included facilities inspecting on an annual basis and every two years. The CL 

analysis seems to assume that components will begin leaking again shortly after they are 

repaired, supporting the conclusion that more frequent surveys will help to drive down 

emissions. 

• Subpart OOOO TSD – EPA’s July 2011 technical support document for the proposed oil 

and gas sector NSPS assumed that control effectiveness has a hyperbolic relationship 

with monitoring frequency.38

 

D. Two-Step LDAR (Question 10) 

Finally, EPA requests comment on the feasibility, cost, and effectiveness of a two-step 

LDAR approach. Traditional, one-step LDAR programs require screening of all potential leak 

sources at facilities despite evidence indicating that in most cases less than 2% of components 

will actually be leaking. Even among leaking components a small percentage of leaks (i.e. those 

that are the largest) generally account for a large majority of total leak volume. As described 

above, data from 375 gas production facilities in Fort Worth indicates that 35% of sites 

accounted for 95% of total estimated annual emissions from leaks, while only 14% of sites 

accounted for 80% of emissions.39 

A two-step LDAR process can take advantage of this leak distribution pattern to reduce 

average LDAR costs for a group of distributed gas production sites. Under a two-step approach, 

operators would use an ambient methane monitor mounted on a vehicle (or other screening 

technology) to quickly determine whether there was a significant leak(s) at the facility, without 

actually pin-pointing or quantifying the leak(s). In the second step, operators would use OVA or 

OGI to pinpoint the actual leaks for repair. Facilities not identified as leaking during the first step 

would not be checked during the second step. This approach has the potential to significantly 

reduce total monthly screening time for a group of distributed facilities. 

EDF used many of EPA’s assumptions in the Subpart OOOO TSD to model the cost of a 

two-step approach and determined that, for EPA Model 2 facilities, control costs were $5/ton of 

methane reduced.40 For this analysis, EDF assumed a population of 375 production facilities 

with average emissions equivalent to the “Model 2” well site described in the Subpart OOOO 

TSD, but distributed in the same way as the Fort Worth dataset. EDF also assumed that mobile 

 

37 ICF Cost Curve Report, supra note 3, at 3-10. 

38 EPA, Oil and Natural Gas Sector: Standards of Performance for Crude Oil and Natural Gas Production, 

Transmission, and Distribution, Background Technical Support Document for Proposed Standards, at 8-26 (Aug. 

2011). 

39 See Figure 1. 

40 The assumptions underlying this analysis are provided in a spreadsheet attached as an exhibit. 
ENVIRONMENTAL DEFENSE FUND • JUNE 16, 2014 

20 

screening would be sensitive enough to identify the highest-emitting sites responsible for 

approximately 80% of total emissions from the population. 

Southwestern Energy is likewise testing this approach in the field and presented results of 

that testing in a February presentation at the Natural GasStar Technology Transfer Workshop. Of 

note, Southwestern was able to survey 21 well sites and 3 drill rigs with this technology in 

approximately 17 hours. Moreover, Southwestern found that leaks exhibited a gross-emitter or 

fat tail distribution and that mobile surveyor results compared favorably to Hi-Flow 

measurements taken onsite.41

V. CONCLUSION 

Even as the data improves on the national methane emissions rate, years of scientific 

study and industry experience make clear that leaks are both widespread and substantial. But it is 

equally clear that the lead control strategy – holistic LDAR deployed at the site level across the 

value chain – is proven and cost effective. OGI technology is effective, efficient, and spreading 

both in voluntary corporate use and inclusion in emerging state policy constructs. As Exxon 

Mobil itself wrote after conducting its own study of OGI,42 “the study results are very promising 

and indicate that any concerns are easily addressed or unfounded”. This finding is consistent 

with the recent experience of Southwestern Energy, the industry-vetted analysis of the ICF 

Report, the quantitative data compiled from thousands of real world surveys performed for the 

Carbon Limits paper, and ample anecdotal evidence from our engagement with operators. 

Moreover, as technology offerings continue to evolve in response to market demand signals and 

state policy drivers, the universe of cost effective LDAR solutions will likely only expand. 

VI. EXHIBITS 

1. EDF analysis of site emissions data from Fort Worth and Allen studies, Fort Worth & 

UT Site Emissions.xlsx (May 2014) 

2. EDF comparison of OGI & Method 21 effectiveness based on Fort Worth study, Fort 

Worth OGI & Method 21 comparison.xlsx (May 2014) 

3. EDF analysis of cost-effectiveness of “two-step” LDAR, EDF-Two-StepAnalysis.xlsx (August 2013). 

 

41 See Southwestern presentation, supra note 31. 

42 ExxonMobil Chemcial Co., “Smart LDAR: Pipe Dream or Potential Reality”, available at

http://www.flir.com/uploadedFiles/Thermography_USA/Industries/OGI/5_Smart_LDAR.pdf.