Capstone Turbine Corporation ● 21211 Nordhoff Street ● Chatsworth, CA 91311 www.capstoneturbine.com U.S. EPA Office of Air Quality Planning and Standards (OAQPS) 109 T.W. Alexander Drive, Research Triangle Park, NC 27711

RE: White Papers on Methane and VOC Emissions in the Oil and Natural Gas Sector

On behalf of Capstone Turbine Corporation, the leading manufacturer of microturbines, I appreciate the opportunity to submit these comments in response to the EPA’s Oil Well Completions and Associated Gas during Ongoing Production white paper released in A pril 2014. These comments focus on section 5.5.3, “Electricity Generation for Use Onsite.”

A microturbine is a small combustion turbine used to generate electricity at the location of the end

- use customer. Capstone microturbines reliably power onshore and offshore oil and gas production operations using unprocessed wellhead gas (economic or flare, sweet or sour up to 7% H2S ) to generate 3

- phase,

load

- following continuous power. As the white paper notes, onsite generation reduces flaring and generates elect ricity for on

- site use, displacing diesel transport costs and resulting emissions.

I applaud the white paper for recognizing the benefits of using associated gas at oil and gas production sites to provide on

- site electricity. Utilizing microturbines both reduces the quantity of methane gas flared

and the volume of fuel transported and us ed for onsite power needs during production. However, some of the data and methodology seem to include errors and misapplied comparisons that skew the results

.

1. Inaccurate microturbine price and performance data skews comparison of on

- site generation

tech nologies

The white paper, citing a 2013 EERC study, compares the capital and operating costs of a 200

- kW microturbine system and a 250

- kW reciprocating engine . Some of the data surrounding the microturbine data should be changed to reflect current techno logy and more accurate performance metrics. This in part reflects the fact that the 2013 EERC study pulled information from a 2003 technical report issued by the National Renewal Energy Laboratory and the Gas Technology Institute. For example, the 2003 rep ort categorized microturbines as an “immature” technology because units began commercial service only in 2000. Now, fourteen years and over 7

, 0 00 microturbines later, Capstone microturbines are a mature technology.

The cost comparison of technology solutions to reduce flaring in Section 5.5.3 is helpful, but the calculations do not reflect the most accurate costs and performance data for microturbines, leading to an

inaccurate conclusion in the white paper that could discourage oil and gas producers from pursuing this option. For instance, the white paper lists the cost of four 65

- kW microturbine systems as approximately $383,000 . Neither the white paper nor the underlying EERC study mention whether this figure reflects the cost before or after the purchaser utilizes the ten percent federal investment tax credit available for microturbines. The tax credit, which lowers the total capital cost by ten p ercent, exists for microturbines but not reciprocating engines, and that is one factor that lowers the upfront capital cost for microturbines.

In addition, a more useful comparison than first costs c ould be lifecycle cost analysi s

. Microturbines provide low emissions on a wide range of fuels without any pre

- or post

- treatment and eliminate the consumables and ongoing expense of reciprocating engin e emissions control systems. This ensures low emissions regardless of adherence to a maintenance schedule. The Capstone Factory Protection Plan covers all planned and unplanned maintenance and the cost of an overhaul at 40,000 hours of operation

. It is unclear what is included in the annual O&M costs for reciprocating engine, but the low price suggests it does not include unplanned maintenance, an overhaul or additional costs needed to operate andCapstone Turbine Corporation ● 21211 Nordhoff Street ● Chatsworth, CA 91311 www.capstoneturbine.com maintain any emis sions control system (e.g. urea, etc.) . With our FPP

– even including overhaul

– our annual O&M costs are easily lower than 10% of the capital cost of the microturbine.

2. Inconsistent/Arbitrary application of system size , cost and fuel use comparison and unequal treatment under “worst case scenario” unnecessarily penalizes microturbine assessment

The EERC study data cited in the white paper is unclear on what is included in the comparison. It initially states that the case study compares a power production scenario of 1 MW for the reciprocating engine

and 200 kW for the microturbine. It notes that the flare station will be larger for the microturbine application since it consumes <100 mcf/day and the excess fuel would be flared. Figure 5

- 5 assumes 510 mcf/day of fuel is produced for both the engine and microturbine scenarios. This means either the 250 kW engine has low fuel efficiency or a 1 MW engine was used so it can operate loads up to five times that of
the microturbine and use five tim es the fuel. If a 1 MW engine system was used, then the cost estimates should reflect that scenario. In the white paper , for the engine, the costs included were for a single 250

kW genset at $200,000 instead of four 250

- kW engines to generate 1 MW. Total cos ts for a 1 MW system

would presumably be 4 x $200,000 = $800,000 and O&M costs at 10% of $80,000.

For the microturbine, the case study uses four 65

- kW microturbines, but states that these will produce only 195 kW because the study assumes worst case scenario operating conditions and derates what would be a higher nominal capacity rating of 4 x 65 = 260 kw. This included a 2,250

- foot above sea level elevation and maximum ambient temperature of 100 degrees F, resulti ng in a derated output of between

20

- 25%. There is no discussion of possible derating of the reciprocating engine in worst case scenario operating conditions though the EPA’s Technology Characterization of reciprocating engines notes that

this elevation an d temperature would lead to some level of derate

. 1 I would think that t he maximum derate only applies for around 100 hours of operation a year (the hottest part of the day during the hottest part of the year). If the recip rocating engine is not derated, it is likely using a turbocharger to adjust for altitude,

which would reduce the overall efficiency of the system

. Perhaps a better approach would be to use an average yearly ambient temperature. Derate information is typically used to size a system for a specific

use. Maximum derate does not apply throughout the year (as temperature varies seasonally) and unfairly

limits the estimate of the actual kWh our system would produce over the course of a year

. Producing a similar compar ison today (vs. the 2003 data used in the EERC study), substituting a single 200

- kW

microturbine would not only lower the capital cost compared to four separate smaller units , but it also offers higher efficiency at 31

- 33% LHV

. 2 The larger microturbine could also be multi

- packed into a 1 MW

solution (five 200

- kW turbines) to more fairly compare the costs and fuel use of the two systems and still provide the flexibility the EERC study used as a reason to opt for the four 65

- kW microturbines

. 3

The stud y authors should clearly state the two scenarios ’ size , emissions, cost and fuel use

. I would

recommend compar ing an engine system and a microturbine system that use a similar amount of fuel since the focus of the study is on how to make use of the wellhead associated gas . Instead of penalizing the microturbine for consuming less gas per day simply because the authors artificially selected a smaller sized turbine package, the white paper should consider a more realistic comparison of technology suite d
to the amount of associated gas available from a site as well as onsite power needs and the possibility of exporting excess power to the grid

. The white paper should also consider that oil and gas companies value the portability of local generation optio ns versus a static pipeline and

– for microturbines specifically

– value the ease of installation, low fuel treatment costs , lower lifecycle costs, and scalability to suit changing well outputs.

1 EP A, “Technology Characterization: Reciprocating Engines.” December 2008, at 11. http://www.epa.gov/chp/documents/catalog_chptech_reciprocating_engines.pdf

2 Capstone Turbine Corporation, “Product Catalog.” http://www.capstoneturbine.com/_docs/Product%20Catalog_ENGLISH_LR.pdf

3 Energy and Environmental Research Center (EERC), “End Us e Technology Study: An Assessment of Alternative Uses for Associated Gas,”April 2013, at 72. http://www.undeerc.org/bakken/pdfs/CW_Tech_Study_April

- 2013.pdfCapstone Turbine Corporation ● 21211 Nordhoff Street ● Chatsworth, CA 91311 www.capstoneturbine.com 3. Gas conditioning requirements for microturbine operation ar e inaccurate and study conclusion
fails to factor in costs and gas conditioning needs for pipeline alternative

The study assumes the same gas conditioning requirements on a 195 kW microturbine plant as are needed for pipeline injection of wellhead gas

. Wellhead gas treatment for injection to pipeline or for use in a reciprocating engine requires more conditioning than for use in a Capstone microturbine. Pipeline pressures also tend to be in the high hundreds PSI, requiring much higher compression energy co sts than needed for a Capstone m icroturbine. A gas processing skid with compression for a single 65 kW turbine would be around $45,000 and does not scale linearly. A 200 kW microturbine would use a skid that cost around $60,000

.

Even if you do use the $2.5 million cost estimate for gas conditioning, this cost would also occur in the

even t the site eventually proceeds to pipeline injection of the produced gas. 4 Since that processing cost comprises 73 percent of the estimated total capital investment for onsite microturbine generation ($2.5 million out of $3.382 m illion), according to the study , having to make that investment in any case for pipeline injection ma kes on

- site generation even more economical in comparison. It’s no surprise then that Capstone has seen growing demand for microturbines at oil and gas production sites. Sixty percent of our global sales and almost eight y percent of our U.S. sales in fisca l year 2014 came from oil and gas

sales. While on site generation may not always be the most efficient choice, particularly when pipeline infrastructure is nearby and gas production is high enough to justify pipeline extension , our experience

has shown that on

- site microturbine generation remains a cost

- effective solution in many circumstances.

The study concludes that microturbines can provide a payback of investment in three years or less, but “given the substantial upfront capital costs of these options , these options may not be preferable to building the necessary pipeline infrastructure to take the gas to market.” 5 After such a thorough economic analysis of various onsite generation options, the white paper fails to elaborate on t he costs need to install that pipeline infrastructure. The costs for necessary easements and construction vary by site (some drilling locations are very remote) but are substantial. For the typical shale wellhead, the flows and values of the produced gas r esult in economics that do not justify a pipeline and often do not justify a grid

interconnect

– if grid power is even available. In these cases, the best economics are achieved with electric generation onsite from the produced gas.

4. Reconsider options for use of any excess electricity, including gas by wire

The white paper states that “grid support requires an infrastructure similar in scope as that needed to bring gas to market,” and thus it is not considered to be an emissions reduction techn ology. The authors state that, “it is unlikely that a well site that is lacking pipeline infrastructure would have access to the necessary infrastructure to provide grid support.” However, in the analysis of local power options, the white paper, in citing the EERC study, assumes that any excess electricity from the site is delivered to the grid. Realistic scenarios of pipeline sales of gas require both a pipeline and power lines to provide grid power for conditioning equipment. Gas

- by

- wire eliminates the co st of building a pipeline extension to the site to allow the export of low value gas as higher value electricity with conversion being done through local power options like microturbines. Additionally, selling this excess gas as electricity allows for furt her reductions in emissions as it would likely displace the highest cost or worst emitting utility power generation systems or eliminate the need to build additional central generation.

For example, i n December 2012, North Dakota produced about 25 billion cubic feet of natural gas. Of that amount, 29% was flared or about 233,870,967 standard cubic feet per day. There are two simple approaches to valuing the economic loss of flaring the gas

– its value as electricity and its value as gas

. From a power generation perspective, this amount of flaring is enough to offset 863 MW of generation capacity (using Capstone C1000 microturbine systems), which could produce 642,072,000 kWh of electricity valued at $38 .5 million if electricity is 6 cents a kWh. From a gas distribution perspective, the average price of wellhead gas in the United States in December 2012 was $3.35/thousand cubic feet.

4 Ibid, at 17

- 18

. 5 Ibid

, at 74.