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 April 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 electricity 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 used 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 

technologies 

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 technology 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 report 

categorized microturbines as an “immature” technology because units began commercial service only in 

2000. Now, fourteen years and over 7,000 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 percent, 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 could be lifecycle cost analysis. 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 engine 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 and 
Capstone Turbine Corporation ● 21211 Nordhoff Street ● Chatsworth, CA 91311 

www.capstoneturbine.com

maintain any emissions 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 times 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 

kWgenset at $200,000 instead of four 250-kWengines to generate 1 MW. Total costs 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, resulting 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 and temperature would lead to some level of derate.

1 I would think that the 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 reciprocating 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 comparison 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 study authors should clearly state the two scenarios’ size, emissions, cost and fuel use. I would 

recommend comparing 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 suited 

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 options 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 EPA, “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 Use 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.pdf
Capstone Turbine Corporation ● 21211 Nordhoff Street ● Chatsworth, CA 91311 

www.capstoneturbine.com

3. Gas conditioning requirements for microturbine operation are 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 costs 

than needed for a Capstone microturbine. 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 

event 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 million), according to the study, having to make that investment in any case for 

pipeline injection makes 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 eighty percent of our U.S. sales in fiscal year 2014 came from oil and gas 

sales. While onsite 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 the 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 result 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 technology. 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 cost 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 further 

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, in 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.