Scott Crider Vice President, Federal Government Affairs

1399 New York Avenue, NW Suite 350 Washington, DC 20005

- 4733

Tel: 202.662.1704 Fax: 202.293.2887 Email: scrider@sempra.com

June 16, 2014

To: U.S. EPA Office of Air Quality Planning and Standards Submitted via electronic mail: oilandgas.whitepapers@epa.gov

Re: Oil and Natural Gas Air Pollution Standards White Papers on Methane and VOC Emissions technical comments

Sempra Energy, on behalf of its subsidiaries, Southern California Gas Company, (SoCalGas) and Sempra U.S. Gas & P ower , 1 supports the U.S. Environmental Protection Agency’s (EPA) efforts to promote clean energy in the United States and appreciates the opportunity to comment on EPA’s White Papers on Methane and VOC Emissions in the Oil and Natural Gas Sector. When considering methane emission studies, Sempra Energy requests that EPA employ a science

- based approach that uses accurate and precise data when determining the source of

, and measuring methane emissions , as further discussed in the attached comments

.

I. Background on Sempra Energy and Its Subsidiaries

Sempra Energy is a Fortune 500 energy services holding company based in San Diego, California. With nearly 17,000 employees worldwide, the Sempra Energy companies develop energy infrastructure, operate utili ties, and provide related products and services to more than 31 million consumers using a low

- carbon model that prioritizes natural gas, energy efficiency, renewable power and innovative technologies. Sempra Energy supports efforts to reduce GHG emissions by transitioning to cleaner

- burning fuels and renewable energy.

Our utility SoCalGas provides energy service to 20.9 million people through 5

. 8 million natural gas meters throughout Central and Southern California

. The company’s service territory encompasses approximately 20,000 square miles.

Our subsidiary Sempra U.S. Gas & Power develops clean power solutions in markets throughout the United States with a focus on zero and low

- emission fuels. The company operates more than 1,500 megawatts (MW) of renewable and natural gas

- fueled power plants, including one of the largest photovoltaic solar facilities in the United States. Its natural gas and renewable plants combined generate power for nearly 1 million homes and b usinesses.

1 Sempra U.S. Gas & Power, LLC is not the same company as the California utilities San Diego Gas & Electric Company (SDG&E) or Southern California Gas Company (SoCalGas), and Sempra U.S. Gas & Power, LLC is not regulated by the California Public Utilities Commission.U.S. EPA Office of Air Quality Planning and Standards 6/16/2014 Page 2

II. Natural Gas Transmission and Storage

Due to proactive efforts by the natural gas industry, emissions from the natural gas system overall are on a declining trend. These reductions are the result of advancements in natural gas

sector technologies and best practices. Understanding the rate and location of emissions from the natural gas system

, and the degree to which emissions can be reduced

, is critical to ensure that regulators continue to include natural gas as a viable energy resour ce in future state energy and greenhouse gas ( GHG ) reduction plans.

We believe there are existing data gaps regarding the understanding of GHG emissions for transportation and storage sources and additional efforts are paramount for reconcil ing these data gaps. We support the effort to understand the sources of methane emissions and how those emissions a re measured and reported, though we feel there is additional information available and forthcoming to support EPA in this endeavor. Furthermore, we respectfully suggest that EPA use caution and avoid placing excessive weight on the limited information obtained from previous studies as they may not have current scientific

- based conclusions. For instance, the studies referenced in the EPA White Pape rs may not accurately reflect pipeline emissions because operating practices, as well as the efficiency of operating equipment, have improved over the last 20 years while referenced studies present findings on a limited set of data that is approximately tw o decades old.

As discussed in the attached comments, t here are several efforts currently underway to provide greater transparency on the factors that contribute to the overall methane leakage rate. The Gas Technology Institute (GTI) is updating the emiss ions factors for distribution pipes, meters and regulators. In addition , the Environmental Defense Fund (EDF) is conducting a series of studies on each area of the natural gas supply chain to develop a more science

- based estimate of the methane leakage rat e for the natural gas system. SoCalGas is directly involved in these effort s

. We believe the findings from these studies will better inform sound policies for addressing methane emissions from natural gas local distribution, and foster a more accurate publ ic understanding of methane leakage rates.

III. Conclusion

Understanding the rate and location of methane emissions from the natural gas system is critical to the development of sound energy policies and GHG reduction plans. Please refer to the attached comment s for responses to the questions stemming from the compressors

, leaks and pneumatic d evices white papers.

Thank you for considering Sempra Energy’s comments . Please contact me

at scrider@sempra.com or 202

- 662

- 1704 if you have any questions.

Respectfully Submitted

,

Scott B. Crider Vice President, Federal Government AffairsU.S. EPA Office of Air Quality Planning and Standards 6/16/2014 Page 3

Responses to charge questions from the Report for Oil and Natural Gas Sector Compressors as prepared by the U.S. EPA Office of Air Quality Planning and Standards

1. Please comment on the national estimates of methane emissions and methane emission factors for vented compressor emissions presented in this paper. Please comment on the activity data and the methodologies used for calculating emission factors presented in this

paper.

In gener al, Sempra is in agreement with the intent of this white paper because it is based largely on the Natural Gas Star Program. We respectfully suggest that EPA use caution and avoid placing excessive weight on the limited information obtained from previous st udies as they may not have current scientific

- based conclusions. For instance, the studies currently used may not accurately reflect pipeline emissions because operating practices, as well as the efficiency of operating equipment, have improved over the la st 20 years while referenced studies present findings on a limited set of data that is approximately two decades old. Improved factors can be obtained from newer studies. Over the years, measurement procedures, technology and knowledge of the subject have improved. In Addition , an analysis of the last three years of Subpart W data could be used to better quantify the emissions and its level of contribution to total green house gas emissions

.

2. Did this paper appropriately characterize the different studies and data sources that quantify vented emissions from compressors in the oil and gas sector?

We believe there are newer and therefore more relevant studies in addition to current Subpart W data. Please refer to our comments regarding question 12.

3. Did this paper capture the full range of technologies available to reduce vented emissions from reciprocating compressors and wet seal centrifugal compressors at oil and gas facilities? In particular, are there other options for reducing emissions at exist ing reciprocating or centrifugal compressors? For example, the EPA is aware of “low emissions packing” for reciprocating compressors but has no detailed information on this technology.

We believe the Natural Gas Star Best Management Practices are still a pplicable, and comprehensive. We do not have any experience with “low emission packing” technologies beyond what is discussed in the white paper.

4. Did this paper appropriately characterize the emissions reductions achievable from the emissions mitigat ion technologies discussed for reciprocating compressors and wet seal centrifugal compressors?

We believe this paper appropriately characterized the emissions reductions achievable from the emissions mitigation technologies discussed for reciprocating com pressors and wet seal centrifugal compressors

. We respectfully suggest that e mission factors from newer studies and current Subpart W data could be used to improve the accuracy of the estimates.Responses to charge questions from the Report for Oil and Natural Gas Sector Compressors 6/16/2014 Page 4

5. Did this paper appropriately characterize the capital and operating costs for the technologies discussed for reduction of vented emissions from reciprocating compressors and wet seal centrifugal compressors?

Although the capital and operating costs of the reduction technologies are derived from existing Natural Gas Star and other reports, they may be underestimated. The cost of replacing a packing ring (page 32), $1

, 500, only covers parts. In practice, it’s often not just the packing that is bad and in nee d of replacement. The rod, cross

- head shoes and cross

- head guides may also need refurbishment at the same time, thus raising the cost associated with “packing replacement”. The cost of l abor should also be considered

. While this cost is variable, it typica lly runs from $3

, 000 to $7

, 000. In addition, a lthough the piston rod may need to be replaced, (mentioned at the top of page 30) this is not a common mitigation option, unless the rod is damaged. If the rod is slightly worn around the packing area, the surf ace of the rod is recoated with tungsten carbide and brought back to its original diameter.

While we do not change wet seals to dry, t he costs

, as reported in the paper

, appear to significantly underestimate the total cost

. We estimate the cost of retrofi tting dry seals on an existing 7260 HP centrifugal compressor at about $250,000, rather than the reported $75,000.

6. If there are emissions mitigation options for reciprocating and centrifugal compressors that were not discussed in this paper, please co mment on the pros and cons of those options. Please discuss the efficacy, cost and feasibly for both new and existing compressors.

With the exception of the currency of the economic analysis cited, t he Natural Gas Star Best Management Practices are still current and comprehensive

.

7. Are there technical limitations that make the replacement of wet seals with dry seals impractical at certain existing centrifugal compressors?

As discussed in our comments to question five above, there are several factors th at make the process both costly and time consuming and therefore impractical.

8. Are there technical reasons why an operator would use a wet seal centrifugal compressor without a gas recovery system?

A gas recovery system is technically possible , though more study is needed to determine the economic implications

. As described in the white paper, this requires the installation of a smaller compressor to increase the pressure of the vented natural gas to a minimum of the fuel pressure of the pipeline compre ssor driver (turbine). In addition to the capital costs to install the compressor , analysis should also include ongoing costs to power and maintain the

compressor, as well as the greenhouse gas emissions generated by its operation. It is unclear at this ti me whether the 95% or 99% reduction efficiency discussed in the white paper would be achievable.Responses to charge questions from the Report for Oil and Natural Gas Sector Compressors 6/16/2014 Page 5

9. Are there technical limitations that make the installation of gas capture systems at certain reciprocating compressors impractical?

As discussed above i n question eight, the technical limitations make the installation of gas capture systems at certain reciprocating compressors impractical.

10. Please comment on the prevalence of the different emission mi t igation options in the field.

Sempra’s regulated utility, Southern California Gas Company

, has implemented many Natural Gas Star Best Management Practices, some of which relate to reciprocating compressor packing

. Subpart W measurements indicate actual emissions are lower than published emission factors for reciprocating compressors , which indicates that the actual payback period is much longer than the published value

.
11. Given the substantial benefits of dry seal systems (e.g., lower emissions, less maintenance, and higher efficiency), are you aware o f situations where new wet seal centrifugal compressors are being installed in the field? If so, are there specific applications that require wet seal compressors?

We are not aware of situations where new wet seal centrifugal compressors are being install ed in the field. I t is our understanding that most new systems have dry seal, which is what we would specify.

12. Are there ongoing or planned studies that will substantially improve the current understanding of vented VOC and methane emissions from recipr ocating and centrifugal compressors and available techniques for increased product recovery and emissions reductions?

There are ongoing and planned studies that will substantially improve the current understanding of vented VOC and methane emissions from r eciprocating and centrifugal compressors and available techniques for increased product recovery and emissions reductions. For instance, m ore accurate data has been obtained in the past three years for Subpart W reporting. The Environmental Defense Fund is sponsoring studies on methane emissions from the natural gas system : Conestoga

- Rovers & Associates and Washington State University have conducted a study on the distribution sector, and Colorado State University has conducted a study on transmission and s torage. Results are expected to be released later this year.U.S. EPA Office of Air Quality Planning and Standards 6/16/2014 Page 6

Responses to charge questions from the Report for Oil and Natural Gas Sector Leaks as prepared by the U.S. EPA Office of Air Quality Planning and Standards

1. Did this paper appropriately characterize the different studies and data sources that quantify VOC and methane emissions from leaks in the oil and natural gas sector?

No comment.

2. Please comment on the approaches for quantifying emissions and on the emissi on factors used in the data sources discussed. Please comment on the national estimates of emissions and emission factors for equipment leaks presented in this paper. Please comment on the activity data used to calculate these emissions, both on the total national and regional equipment counts.

No comment.

3. Are the emission estimating procedures and leak detection methods presented here equally applicable to both oil and gas production, processing, and transmission and storage sectors?

We do not believe the emission estimating procedures and leak detection methods presented here equally apply to both oil and gas production, processing and transmission and storage

sectors.

Oil and gas production, processing, transmission and storage sectors all fall under dif ferent GHG reporting categories which reflect different operating environments and equipment. For example, transmission has miles of buried pipe between above ground stations whereas storage is within a small geographical area with mainly aboveground pipi ng. In addition, our storage facilities are located at areas where there is high temperature and high winds. Finally,

our storage facilities operate at a range of 40 lbs. to 3000 lbs. pressure whereas the other sectors tend to operate at approximately 500 lbs. or less.

4. Are there ongoing or planned studies that will substantially improve the current understanding of VOC and methane emissions from leaks and available techniques for detecting those leaks? Please list the additional studies you are aware of.

The Environmen tal Defense Fund is conducting studies on quantifying the amount of methane lost across today’s U.S. natural gas supply chain, including production, gathering lines and processing facilities, long

- distance pipelines and storage, and local utility distribut ion.

Further information on the studies can be found on the EDF website: http://www.edf.org/methaneleakage

5. Are there types of wells sites, gathering and boosting stations, processing plants, and transmissi on and storage stations that are more prone to leaks than others? Some factors that could affect the potential for leaks are the number and types of equipment, the maintenanceResponses to c harge questions from the Report for Oil and Natural Gas Sector Leaks 6/16/2014 Page 7

of that equipment, and the age of the equipment, as well as factors that relate to the local geology. Please discuss these factors and others that you believe to be important.

With regard to above ground storage equipment, based upon our experience and internal company standards and practices which includes but is not limited to daily inspections, routine maintenance and repair, if established maintenance procedures and protocols are followed

, there are no differences in the number and types of equipment, the age or geology that impacts the potential for leaks in th e fields Sempra’s utility, SoCalGas operates.

6. Did this paper capture the full range of technologies available to identify leaks at oil and natural gas facilities?

The paper capture s the full range of existing technologies available to identify leaks beyond soap tests, visual, audible and smell.

7. Please comment on the pros and cons of the different leak detection technologies. Please discuss efficacy, cost and feasibility for various a pplications.

Based on our experience, w e agree with the report on the cons regarding LDIR and Optical cameras as they do not quantify emissions and the accuracy of such devices are extremely sensitive to ambient environmental conditions such as heat and w ind.

SoCalGas experience supports EPA Method 21 as the most efficient and effective methodology for leak detection because it allows detection and quantification in one step.

8. Please comment on the prevalence of the use of the different leak detectio n technologies at oil and gas facilities. Which technologies are the most commonly used? Does the type of facility (e.g., well site versus gathering and boosting station) affect which leak detection technology is used?

The most efficient and effective meth odology for leak detection in Storage is EPA Method 21.

9. Please provide information on current frequencies of revisit of existing voluntary leak detection programs in industry and how the costs and emission reductions achieved vary with different frequenci es of revisit.

The current program at Sempra’s utility, SoCalGas of daily inspections, routine maintenance

, repair and other regulatory required inspections identifies leaks to be addressed

. Increasing the frequency of leak detection surveys does not nece ssarily correlate to a reduction of leaks, and would result in an operational burden

10. Please comment on the potential for using ambient/mobile monitoring technologies in conjunction with OGI technology. This would be a two

- phase approach where the ambient/ mobile monitoring technology is used to detect the presence of a leak and the OGIResponses to c harge questions from the Report for Oil and Natural Gas Sector Leaks 6/16/2014 Page 8

technology is used to identify the leaking component. Please discuss efficacy, cost and feasibility.

Sources of methane emissions other than natural gas , including biogenic a nd naturally occurring thermogenic sources must be ruled out. Isotopic fingerprinting may not be able to differentiate among two petrogenic sources, so an additional tracer, such as helium, should be used. It should be noted that using this technique can be time consuming and costly, especially in populated areas where many other emission sources can exist that require labor to investigate and screen out “false positive” indications.

With regard to t ransmission pipelines

, mobile monitoring can be used in conjunction with OGI technology. These technologies are currently available on both land

- based vehicle and aerial platforms. Mobile technologies used in this manner measure atmospheric levels of methane and identify loc ations where the measured level is significantly above naturally occurring background levels of methane

. Various techniques may then be employed to identify the local source causing the increased atmospheric methane level, which may or may not have been e mitted from a pipeline facility. Once a pipeline emission source is located

, the OGI technology

, along with any of the methods for determining mass fl ow rates

, can then be utilized.

Currently there are no mobile technologies available that are capable of quantifying emission rates, even from known sources of emissions. While this method may serve a purpose for assessing emissions from a facility or upwind source, it should not be considered a “leak detection” technique”. Ambient / mobile monitoring does no t fulfill the functional requirement to identify the leak source and should not be identified as a leak detection technology.

From Sempra’s perspective, facility application mobile monitoring is not consi dered to be a viable or necessary tool because exist ing requirements and practices capture emission

sources.

11. Please comment on the cost of detecting a leak when compared to the cost to repair a leak. Multiple studies described in this paper suggest that detecting leaks is far more costly than repairing lea ks and, due to generally low costs of repair and the subsequent product recovery, it is almost always economical to repair leaks once they are found. Please comment on this overall conclusion.

T he cost of detecting a leak is far cheaper than repairing a l eak. Factors that should be addressed include but are not limited to:

a. Labor/material/administrative costs

b. Valve replacement costs

c. Amounts of gas blown to atmosphere necessary to conduct certain repairs

d. System outages which impact the availability of equipm ent and potentially impact the availability of gas to customersResponses to c harge questions from the Report for Oil and Natural Gas Sector Leaks 6/16/2014 Page 9

12. If the conclusion is correct that it is almost always economical to repair leaks once they are found, then how important is the quantification of emissions from leaks when implementing a program to detect and repair leaks?

As mentioned, the cost of detect ing a lea k is far cheaper than repairing one. R egardless of economic considerations, quantification of emissions from leaks is necessary to determine an appropriate response to a leak.

13. Please comment on the state of innovation in leak detection technolog ies. Are there new technologies under development that are not discussed in this paper? Are there significant advancements being made in the technologies that are not described in this paper?

The U.S. Department of Energy’s Advanced Research Projects Agenc y

- Energy (ARPA

- E) is soliciting applications for MONITOR, to fund development of innovative, new approaches to methane sensing in order to reduce associated costs to the point that widespread implementation is feasible ( https://arpa

- e

- foa.energy.gov ) . Similarly, EDF is soliciting proposals for th e “Methane Detectors Challenge” to fund development and commercialization of low cost, methane detection technologies to help minimize methane emissi ons in the oil and gas industry ( http://www.edf.org/sites/default/files/mdc_rfp_final.pdf

. ).U.S. EPA Office of Air Quality Planning and Standards 6/16/2014 Page 10

Responses to charge questions from the Report for Oil and Natural Gas Sector Pneumatic Devices as prepared by the U.S. EPA Office of Air Quality Planning and Standards

1. Did this paper appropriately characterize the different studies and data sources that quantify emissions from pneumatic controllers and pneumatic pumps in the oil and gas sector?

No c omment

.
2. Please discuss explanations for the wide range of emissio n rates that have been observed in direct measurement studies of pneumatic controller emissions (e.g., Allen et al., 2013 and Prasino 2013). Are these differences driven purely by the design of the monitored controllers or are there operational characteris tics, such as supply pressure, that play a crucial role in determining emissions?

No comment.

3. Did this paper capture the full range of technologies available to reduce emissions from pneumatic controllers and pneumatic pumps oil and gas facilities?

No comment.

4. Please comment on the pros and cons of the different emission reduction technologies. Please discuss efficacy, cost and feasibility for both new and existing pneumatics.
In many instances, physical a sset protection and public safety considerat ion s outweigh margin al reduction in GHG attainable by use of less

- reliable assets. Electric controllers are not as reliable

as pn eu matics in practical remote pipeline applications ; and where two forms of overpressure protection system are required and prudent for pipeli ne operations, one of the forms should be a fully

- autonomous pneumatic control, which is n ot impacted by grounding, light ning strikes or other electrical issues. This is also the case for critical pipeline valve operations.

5. Please comment on the prevalence of the different emission control technologies and the different types of pneumatics in the field. What particular activities require high bleed pneumatic controllers and how prevalent are they in the field?

No comm ent.

6. What are the barriers to installing instrument air systems for converting natural gas

- driven pneumatic pumps and pneumatic controllers to air

- driven pumps and controllers?
The principal barriers to installing instrument air systems for converting natural gas

- driven pneumatic pumps and pneumatic controllers to air

- driven pumps and controllers are c ost and reliability . Using existing gas pressure to cont rol gas in the pipeline does not depend on an air

compressor and electric systems to r emain functional. When you use natural gas

- driven controllers, you are assured that in every instance you have gas in the pipeline, you have gas

pressure avai la ble for the control system. This is n ot always the case using air

- driven pumps and controllers . Relying on a local compressor, served from the electric grid

, introduces two additional major points of failure into an overall risk/reliabilty model. In a large stationResponses to charge questions from the Report for Oil and Natural Gas Sector Pneumatic Devices 6/16/2014 Page 11

(com p ressor station), building the electical and air compressor redundancy makes s ome sense , b ut at a remote valve station, it lacks technical or economic rationale

.
7. Are there situations where it may be infeasible to use air driven pumps and controllers in place of natural gas

- driven pumps and controllers even where it is feasible to install an instrument air system?

No comment.

8. Did this paper correctly characterize the limitations of electric

- powered pneumatic controllers and pneumatic pumps?

N o comment.

Are these electric devices applicable to a broader range of the oil and gas sector than this paper suggests?

No comment.

9. Are there ongoing or planned studies that will substantially improve the current understanding of VOC and methane emissions from pneumatic controllers and pneumatic pumps and available techniques for inc reased product recovery and emissions reductions?
The Environmental Defense Fund sponsored a study conducted by the University of Texas on natural gas production, released in 2013. A second phase of the project will focus on pneumatics. A link to the UT study can be accessed by: www.edf.org/climate/methane

- studies/UT

- study

- faq

.