### Technical Support Document (TSD) for

New Source Performance Standa rds for Carbon Pollution from Electric Utility Generating Units (EGUs) Docket ID No. EPA-HQ-OAR-2013-0495 Docket ID No. EPA-HQ-OAR-2013-0603



# Achievability of NSPS

for Fired Combustion Turbines

U.S. Environmental Protection Agency

Office of Air and Radiation August, 2015

### Page | 2 

### Summary

To establish an appropriate standard for combustion turbines, we reviewed the emissions rates of natural gas-fired (non-CHP) combined cycle units in the power sector that commen ced operation on or after January 1, 2000. We only c onsidered EGUs that reported both the electrical output from thecombustion turbine-generator and the steam turbinegenerator.

Introduction

The purpose of this study is to determine how existing natural gas-fired 1 

### combined cycle (NGCC) units have performed in comparison to the final standards. The study is based on hourly emissions and operating data repo rted to the Environmental Protection Agency (EPA) and to the Energy Information Administration (EIA ). Approximately 4,700 elect ricity generating units 2 

### are subject to the Acid Rain or Clean Air Interstate Rule programs. Of these, some 1,000 are NGCC units located in 41 states that encompass a diverse population in terms of capacity, years of serv ice and configuration. This study also explores the extent that operational and geographic factors (such as cycli ng, ambient temperature, and elevation) affect CO 2 

### emission rates and thermal efficiencies . Manufacturers of NGCC technologies are continuously improving the capabilities of these units to serve a broad range of system load profiles while improving thermal efficiencies 3 

### to reduce marginal fuel co sts. Since this study is retr ospective (i.e., this study is evaluating the performance of older, less-efficient NGCC technologi es), this study is inherently conservative because the performance of new sources with the latest technologies fo r optimizing efficiencies is expected to result in lower emissions given simila r operating profiles. Additiona lly, this study has been updated since the proposed rule to include operat ing data through 2014 that reflects any changes in performance attributable to the increasing use of interm ittent renewables, particular ly in the western United

States.

The term ‘unit’ here refers to a natural gas-fired com bustion turbine, heat recovery steam generator, and any

duct burners associated with a particular set of electrici ty generators together in various configurations; these components taken together are commonly called combin ed cycle “power blocks.” These configurations generally fall into two groups: (1) si ngle-shaft power blocks, where the combustion turbine, steam turbine, and electricity generator all share a common shaft; and (2) multiple-shaft power blocks, where each combustion turbine in the power block shares a shaft with a separate electricity generator and the steam turbine in the power block is on a completely separate sh aft with an additional electricity generator. In this analysis when referring to various counts, we are referring to the number of combustion turbines. The analysis includes operating data from 345 combustion turbines within combined cycle power blocks.

The analysis covers monthly emissions and ope rating data from 2007 to 2014. The study includes only

those months where both CO 2 

### emissions and gross MWh output were gr eater than zero. Not all units ran for all 96 months so the total number of ‘unit operat ing months’ used in this analysis is 22,913 out of

1 Natural gas refers to the primary fuel as reported to the EPA and includes both ‘Natural Gas’ and ‘Pipeline Natural Gas’. ‘Process

Gas’ and ‘Other Gas’ units, typically associated with industrial production, are excluded.

2 An electricity generating unit may be referred to as a ‘facility’ under NSPS

3 http://www.westgov.org/wieb/electric/Transmission%20Protocol/SSG

‐ WI/pnw_5pp_02.pdf See vintage heat rate improvement;

the annual average is assumed to improve ‐ 0.6% per year over 2002

‐ 25. 

### Abbrev.

CHP

CO2

EGU

EPA

MMBtu

MW

MWh

NGCC combined heat and power

carbon dioxide

electric generating unit

U.S. Environmental Protection Agency

million British thermal units (unit of energy)

megawatt(s) – one million watts

megawatt-hour(s)

natural gas combined cycle

### Page | 3 

### 33,120 potential unit operating months included in the study period.

Emissions and operating data used in this analysis are publically available for download, including unit capacity, fuel type, monthly operating time, CO2 em issions and gross output in megawatt hours (MWh). 4


### The publically available data is essentially the same data that would be used for compliance

determinations since ther e is no bias adjustment 5 

### in Appendix G of Part 75 for units using fuel meters to

determine CO 2 

### emissions.

The unit population is filtered to include only those NGCC units that report natural gas or pipeline natural gas as the primary fuel, are in the electric utility or small power producer source categories

and have commercial operation dates on or after January 1, 2000. In addition, the study is limited to those units that reported gross output data from both the primary combustion turbine and steam generator during the study period. 6 

### The study

also excludes all units at plants where combined heat and power (i.e., cogeneration) is reported. 7



### The resulting population of 345 NGCC units is hete rogeneous in location, age, capacity and operating profile. They are located in 35 states and all 10 EPA regions, as shown in Table 1 . Both large and small states are represented, including Califor nia with 43 units and Rhode Island with 3.

Table 2 summarizes the study population by the year they entered service from 2000 thr ough 2013. The average study unit has been in service for over 8 y ears. The study population in cludes 11 units that our

research determined were retrofits or conversions of simple cycle turbines to NGCC or that operated in single cycle mode for a period of time during commencement of operations. In output capacity, the units range from 62 to 480 MW with an average capacity of 320 MW. The mean annual percent electric sales during the study period was 37 percent, but ranged from a low of 32 per cent in 2008 to a high of 44 percent in 2012. Between 2007 and 2014, the annual CO 2 

### rate, expressed in pounds of CO 2 

### per megawatt hour of gross output (lb CO 2 

### /MWh), was consistently in the range of 780 to 980 lb CO 2 

### /MWh, while the count of operating units grew from 264 to 345.

4 Data is available at http://ampd.epa.gov/ampd/.

5 See part 75 in Volume 40 of the Code of Federal Regulations (CFR) originally published in January 1993.

6 Reporting output from the steam generator is optional. See 40 CFR part 75.

7 Excludes units at plants with any cogeneration or CHP noted in eGRID, Greenhouse Gas Reporting Program, CAMD, Ventyx (EIA), or

NEEDs databases. State EPA
Region Units MW
Capacity State EPA
Region Units MW
Capacity State EPA
Region Units MW
Capacity

AL 4 20 6,750 MA 1 2 858 OH 5 10 3,518

AR 6 20 4,854 ME 1 3 908 OK 6 19 6,349

AZ 9 22 7,274 MI 5 3 1,206 PA 3 12 3,682

CA 9 43 11,587 MN 5 6 1,993 RI 1 3 921

CO 8 5 1,101 MO 7 2 508 SD 5 1 310

CT 1 4 1,292 MS 4 16 5,114 TN 4 5 1,709

FL 4 27 10,690 NE 7 2 290 TX 6 35 10,676

GA 4 14 5,720 NV 9 6 1,944 UT 8 5 1,341

ID 10 1 314 NH 1 2 580 VA 3 7 2,322

IL 5 8 2,475 NM 6 4 1,250 WA 10 4 1,282

IN 5 2 690 NY 2 11 3,666 WI 5 8 2,799

LA 6 7 2,225 NC 4 6 2,258 

### Table 1. Study Units by EPA region and State

### Page | 4 

### Table 2. Study Units by Age and Capacity

Year in Service Units Capacity (MW)

2000 22 5,970

2001 33 10,401

2002 71 20,647

2003 62 21,392

2004 18 5,582

2005 34 9,960

2006 9 3,131

2007 6 1,605

2008 26 9,084

2009 13 5,165

2010 9 3,387

2011 24 7,578

2012 14 5,150

2013 4 1,404



### Level of the Standard

The final rule establishes three subcategories for base load, non-base load, and multi-fuel-fired combustion turbines. These subcategories reflect the degree of limita tion that is achievable for specific classes of EGUs based on their percentage electric sales and percentage of natural gas use. The level of the standard for each of the subcategories is discu ssed in the following sections:

Standard for the Base Load Natural Gas-fired Subcategory. The final standard for the base load natural gas-fired subcategory is 1,000 lbs CO 2 

### /MWh. This standard reflects the de gree of emission limitation that has been demonstrated by combined cycle combustion tu rbines firing more than 90 percent natural gas (on a heat input basis) during periods when the percentage of electric sales is greater than 50 percent. The final standard is based on combined cycle performance that has been demonstrated acro ss the full range of midto high-load conditions from combined cycle units. However applicability of the standard is not limited to combined cycle units. The standard applies to any combustion turbin e during 12-operating month rolling periods when natural gas provides more than 90 percent of heat input, if the 12-m onth period occurs within a 3-year rolling period 8 

### when the EGU supplies more than its design efficiency 9 

### times its potential electric

8 The base load electric sales criteria includes both a 12

‐ operating month and 3 year electric sales threshold. Throughout this

document we are simple using the shorthand of 3 year electric sales threshold.

9 The unit

‐ specific percent electric sales applicability threshold is based on the design efficiency of the combined cycle power block,

but the threshold threshold cannot exceed 50 percent. For example, a new combined cycle power block with a design efficiency at

baseload conditions of 57 percent would be subcategorized as a base load unit during a year when the actual percent electric sales

was 52 percent, but this same unit would be subcategorized as a non

‐ baseload unit during a year when the actual percent electric

### Page | 5 

### output as net-electric sales. Based on analysis of this data we have determined that a standard of 1,000 lb

CO 2 

### /MWh-g is achievable for natural ga s-fired base load combustion turbin es regardless of size. Therefore, the final rule does not include subcategories for sma ll and large combustion turbines. In addition, based on comparing the cost of electricity from simple cycle a nd combined cycle units, it is cost effective to use a combined cycle unit when operating as a base load unit. Therefore, this final rule has minimal compliance

costs since it is cost effective ba sed on fuel savings alone. The costi ng analysis compared the generation costs of advanced combine units to advanced simple cycle units. The EPA notes that the distinction between

“advanced” and “conventional” is based on incremental design improvements. Table 3 presents the EIA

definitions for these two classes of combined cycle technologies.

Table 3: EIA Definitions of Combined Cycle Design Classes

Conventional Natural Gas Combined Cycle (NGCC)

The Conventional NGCC produces 620 MW of net electricity. The facility utilizes 2 natural gas-fueled F5-class CTs and associated electric generators, 2 supplemental-fi red heat recovery steam generators (“HRSG”), and 1 condensing ST and associated electric generator operating in combined-cycle mode. Each CT is designed to produce nominally 205 MW and includes a dry-low NOX combustion system and a hydrogen-cooled electric generator. The 2 triple-pressure HRSGs include integrated deaerators, SCRs, oxidation catalyst for control of carbon monoxide and supplemental duct firing w ith combustion management. The ST is a single-reheat condensing ST designed for variable pressure operation, designed to pr oduce an additional 210 MW. The ST exhaust is cooled in a closed-loop condenser system with a mechanical draft cooling tower. The CTs are equipped with inlet evaporative coolers to reduce the temperature of the tu rbine inlet air to increase summer output. The Conventional NGCC plant also includes a raw water treatment system cons isting of clarifiers and filte rs and a turbine hall, in
which the CTs, ST, and HRSGs are enclosed to avoid freezing during periods of cold ambient temperatures.

Advanced Generation Natural Ga s Combined Cycle (AG-NGCC)

The Advanced Generation (“AG”)-NGCC design is the sa me as the Conventional NGCC, except an H-class CT is utilized in lieu of F-class, and there is only one CT/HRS G supporting the ST included. Since the H-class CT design employs steam cooling of both stationary and rotati onal hot parts, the HRSG systems and the ST are both considered “advanced” designs, as compared to th e Conventional NGCC. The AG-NGCC has advantages compared to the Conventional NGCC. The advantages of th e AG-NGCC are for the same size of equipment – more megawatt output due to higher firing temperature. The hi gher firing temperature is due to more technically advanced metallurgy, coatings, and blade cooling syst ems. The AG-NGCC may or may not have a better ramping rate depending on the geographical location of the f acility. The net output of the AG-NGCC is 400 MW.



### Compliance Calculations

Compliance with the standard in th e final rule is determined by calcu lating the 12-operating month rolling average. To calculate compliance fo r a given unit, the unit’s total CO 2 

### emissions over the twelve previous operating months is divided by either the unit’s total energy output (in MWh) or the total energy input (in MMBtu) over that period. Th e generalized formula is:

A = C / M

A is the 12-operating month rolling average (lb CO 2 

### /MWh or lb CO 2 

### /MMBtu).

C is total CO 2 

### emissions for the 12 month periods in pounds. For base load units, M is total energy output for the 12 month period in MWh. For non-base load, M is the total heat input from all fuels fired.

sales was 48 percent.

### Page | 6 

### Since the study period is 96 months long the maxi mum number of rolling average results is 85. An ‘exceedance,’ as used here, means that a unit exceeded the applicable subcategory standard of performance for one 12-month rolling average. Since the calculation on ly includes operating months, the actual time span covered may be more than a calendar year. For example, if a unit started operation in January 2007, but did not operate in March of that ye ar, the first rolling average would not be available until the en d of January 2008. Unless stated otherwise, the term ‘CO 2 

### rate’ as used here means the 12-month rolling average CO 2 

### emission

rate.

There are a number of advantages to using this approach. A 12-month rolling average balances seasonal variations in thermal performance because EGUs may perfor m differently in winter than in summer and use of a 12-month average reflects the over all performance of the unit acro ss all meteorological conditions. Additionally, the standard applies at all times including periods of startup, shutdow n, and malfunctions. Use of a 12-month period allows sufficient time for a unit to off-set the unavoidable efficiency penalty that occurs during unit start up.

Fleet Averages

The EPA calculated the 12-month rolling averages for th is study using hourly unit em issions data aggregated to the monthly level. The key parameters examined are monthly CO 2 

### mass (lbs), gross output (MWh), and operating time (hours). The calculati on is based on operating months (i.e., months in which both CO 2 

### mass emissions and gross output are greater th an zero). The fleet average monthly CO 2 

### rate 9 

### for all study units is

857 lb CO 2 

### /MWh with a distribution, s h o w n i n Figure 1

, which is slightly right-tailed due to four units with higher rates that exceeded three st andard deviations from the mean.

Figure 1: Study Unit 12-Month Average CO 2 

### Rate Distribution 2007-2014

The average unit percentage electric sales for all units was 37 percent. This average was comprised of a wide range of percentage electric with the 2nd percentile value equal to 3 percent and the 98 th 

### percentile value equal to 70 percent. 10 

### Similarly, the 12-month average emission rates was comprised of a wide range

10 Eight

‐ year percentage electric sales include only years with MW generation reported.NormalDistribution

0 0.001 0.002 0.003 0.004 0.005 0.006



### 600 800 1,000 1,200 1,400 1,600 

## All 12

‐ Month Averages of Study Units

lb CO2/MWh

### Page | 7 

### of values with the 2 nd 

### percentile equal to 754 lbs CO 2 

### per MWh and the 98 th 

### percentile value equal to

1065 lbs CO 2 

### /MWh.

Exceedances

Out of 345 units, 320 had no exceedan ces during the eight year study pe riod even without filtering outperiods of operation as non-base load units. However, without filtering out periods of operation as nonbase load units this overestimates the number of actual exceedances. The base load standard is only applicable during 12-month averages where the perc entage electric sales are above the threshold. Twenty four of the units appeared to be operati ng as non-base load units when the exceeding an emission rate of 1,000 lb CO 2 

### /MWh-g. Therefore, essentially all th e NGCC units in this analysis have demonstrated that the base load natural gas-fired com bustion turbine standard included in this final rule is

achievable.

Site Specific Factors

Many commenters stated that the EPA needs to account for site specific factors such as ambient conditions (e.g., temperature and elevation), operating parameters (e .g., number of starts), cooling type, degredation, and the use of backup fuel. No comments were submitted that changed our analysis at proposal for the first two factors (ambient conditions and operating parameters). As described in the preamble to this final rule, units with dry cooling towers had an average 12-ope rating month maximum emission rate of 875 lb CO 2 

### /MWh-g. This is lower than the fleet average 12-opera ting month maximum emissi on rate of 897 lb CO 2 

### /MWh-g. Therefore, the final base load standard has been demonstrated as achievable by units electing to use dry cooling systems. To evaluate degredation, the EPA determined the change in the average annual emission rate. Overall, the median annual emission rates of indi vidual units is decreasing at 0.10 percent. Therefore, the average emission rate for individual NGCC units is essentially constant with limited degredation evident in the data. Due to two factors, the use of backup fuel would in theory increase the emission rate of a base load unit by approximately 4 percent. First, accordi ng to Gas Turbine World, th e heat rate will increase between 1 to 2 percent when firing distillate oil rela tive to the heat rate when firing natural gas. The efficiency impact would be negligible for base load units since it is limited to units burned greater than 90 percent natural gas. The primary fact or increasing the emission rate is th e relative carbon content of the fuels. Co-firing 10 percent distillate oil increases the emi ssion rate on a lb/MMBtu basis by slightly less than 4 percent relative to burning 100 percent natural gas. Howeve r, the vast majority of units operating at base load conditions (i.e., percentage of electric sales of great er than 50 percent) have a maximum 12-operating month average of less than 960 lb CO2/MWh-g. Therefore, the final standard in this rule includes sufficient compliance margin for the use of backup fuels.

Temperature

Combustion turbines generally are less efficient wh en ambient temperatures are highest, however, a comparison of winter monthly (December, January a nd February) to summer mont hly (June, July, August) rolling average CO 2 

### rates in this study found no difference overa ll in the NGCC CO 2 

### emission rate. Both time periods had nearly id entical fleet average CO 2 

### rates of 863 lb CO 2 

### /MWh. Less than half of the units operating in both time periods, had lower rollin g average rates in the summer months.

Using the actual monthly summer-winter monthly data (ra ther than the 12-month rolling average CO2 rate) finds

that about 60% of the units with both summer and winter data sets had lower rates in the winter months. This finding is consistent with manufact urer performance specifications for winter and summer operating conditions. Looking at individual cases, two of the four units with th e highest percentage difference in actual CO2 rate, i.e., 2-4 % higher in summer months, had exceedances. However, those units are the exception. Over 93 percent of the units with higher actual monthly CO2 rates in summer still met the standard with no exceedances. For the majority of post-2000 NGCC units, the 12-month rolling av erage CO2 rate avoids exceedances by smoothing

### Page | 8 

### out any increases in CO2 rate that may occur due to ambient temperature.

Pollution Controls
All the units in this study are a ssumed to be equipped with low NO X 

### burners. Nearly 90 percent are also equipped with selective catalytic reduction (SCR) NO X 

### controls. No correlation between the presence of an SCR and higher average CO 2 

### emission rates was evident. In fact, five of the units with exceedances did not have an SCR during the study period.

Cycling

NGCC units can cycle frequently. An exam ination of starts, define d here as the initiation of fuel consumption, found that the average unit started 106 times per calendar year over the study period. Several units in this study cycled over 300 times per calendar year, (i.e., the equivalent of starting up every weekday). The data indicates that NGCC units can cycle very efficiently. There is no correlation between the number of starts and exceedances. Figure 3 plots th e count of starts 2007-2011 (on th e X axis) agains t the average CO 2 

### rate for each unit (on the Y axis). The CO 2 

### rates are evenly distributed ar ound the mean and show limited correlation to the starts. Of the top 50 units with th e most starts, only three had exceedances. The average CO 2 

### rate of the top ten cycling un its, measured by start count ov er the study period, was 882 lb CO 2 

### /MWh, which is well below the performance standard.

### Page | 9 

### FIGURE 2: Unit Star t Ups and Average CO 2 

### Rate 2007-2011

Elevation

The elevation of the units in this study ranges from 1 to 5,276 feet above sea level. There is no correlation between the elevation of a study unit and either the number of exceedances or the average CO 2 

### rate. None of

the units with exceedances is locate d above 1,500 feet. Fifteen units opera ted at elevations above 4,200 feet and had no exceedances during th e study period. The average CO 2 

### rate for the fifteen uni ts at altitudes over 4,000 feet is 862 lbs CO 2 

### /MWh, which would indicate that new units situated at higher elevations can maintain a high standard of efficiency.

Figure 3: Unit Elevation and Average CO 2 

### Rate 2007-2011

### Page | 10 

### Standard for the Non-base Load Natural Gas-fired Subcategory.

The final standard for the non-base load natural gas-fired subcategory is 120 lbs CO 2 

### per MMBtu of heat input. This standard reflec ts the degree of emission limitation de monstrated by combustion turbines firing more than 90 percent natural gas (o n a heat input basis) du ring periods when these units have percentage electric sales less than or equal to their design effi ciency times their potential electric output. The final standard is based on use of natural gas (with a sma ll allowance for use of a b ackup fuel) and encompasses the levels of performance demonstrated by both combined cycle and simple cycle natural gas-fired turbines during periods when they operate at as non-base lod units. This standard applies to any combustion turbine during 12-operating month rolling peri ods when natural gas provides more than 90 percent of heat input, if the 12-month period occurs within a 3-year rolling period when the EGU supplies less than its design efficiency times its potential electric output as net-electri c sales. As described in the preamble to this final rule, this standard is readily achievable.

Standard for the Multi-fuel -fired Subcategory.

The final standard for the multi-fuel-fired subcategory ranges from 120 to 160 lbs CO 2 

### per MMBtu of heat input. The specific standard that appl ies during a particular compliance pe riod is proportional to the fraction of total heat input derived from natural gas. Th is standard reflects the degree of emission limitation demonstrated by combustion turbines firing less than or equal to 90 percent natural gas (heat input basis). The

final standard is based on the use of clean fuels w ith average carbon contents wi thin the range encompassed by natural gas on the lower end and dist illate fuel oil on the upper end. This range encompasses the levels of performance demonstrated by both combined cycle and simple cycle turbines dur ing periods when firing backup fuels or industrial by- product gases. This standard applies to any combustion turbine that is connected to a natural gas pipeline during 12-oper ating month periods when natural ga s provides less th an 90 percent of heat input.

Combustion turbines in this subcat egory are required to pe rform periodic fuel sampling when firing residual fuel oils and non-uniform fuels such as refinery fuel gas. Operators firing gase s that already contain CO 2 

### (prior to combustion) may elec t to utilize periodic sampling to determine the quantity of CO 2 

### in the stream prior to combustion and may exclude this portion from the compliance calculation.

According to the final data published by both CAMD a nd the EIA for 2013, natural gas was used to generate more than 98 percent of all the electricity delivere d to the grid by combustion turbines with nameplate capacities greater than 25 MW. Table 4 presents 2013 data from EIA su mmarizing the generation from combustion turbines firing non-natural gas fuels. These da ta show that the primary, non-natural gas fuels used by combustion turbines for the production of electricity are fuel gas, residual fuel oil, distillate fuel oil, kerosene, and jet fuel. It is noteworth y that the EIA data indicate that the majority of the combustion turbines using these non-natural gas fuels are associate with combined heat and power operations. The final rule includes an option for such CHP operators to take a perm it limit on electric sales to avoid applicability of the

NSPS. As shown in Table 4 the carbon contents of these non-natu ral gas fuels range from 118 to 180 lbs

CO 2 

### /MMBtu HHV. The BSER is based on a weighted average emission limit for periods when natural gas is fired with other fuels in order to limit the usage of high carbon fuels such as hi gh-carbon residual fuel oils. However, the BSER allows continued use of distillate o ils 1 and 2, jet fuel, fuel gas, propane, and liquefied petroleum gas.

### Page | 11 

### Table 4. Non

‐ natural Gas Fuel Use for Electricity Generation 11



### Fuel Average Carbon Content 12 

### Fraction of National

Net Generation

Other Gas 13 

### (fuel gas, propane, liquefied petroleum gas) 14 

### 115 to 139 lbs CO 2 

### /MMBtu 0.49 percent

Coal-derived synthesis gas Not applicable; units are subject

to IGCC standard. 0.19 percent

Residual Fuel Oil (Nos. 5 and 6 and bunker C) 161 to 177 lbs CO2/MMBtu 0.14 percent

Pet. Coke-derived synthesis gas Not applicable; units are subject

to IGCC standard. 0.14 percent

Distillate fuel oils (Nos. 1, 2, and 4) 161 to 166 lbs CO 2 

### /MMBtu 0.09 percent

Kerosene and jet fuel 159 to 166 lbs CO 2 

### /MMBtu 0.05 percent

Other biomass gases and liquids 115 to 180 lbs CO 2 

### /MMBtu 0.01 percent

11 Usage is based on EIA 923 data for RY2013.

12 Average carbon contents taken from Table C

‐ 1 of 40 CFR Part 98 and
http://www.wiley.com/legacy/wileychi/morvayindustrial/supp/toolbox5.pdf

13 The petroleum refining and chemicals sectors reported 0.28 of the 0.49 % shown; the balance was reported by the utilities sector

. 14 EIA does not publish specific fuels within the "Other Gas" fuel code, however EIA does publish the NAICS codes for facilities
reporting this fuel code. The specific fuels listed are the gaseous fuels reported to 40 CFR Part 98 from the NAICS codes that also
reported electricity generation to EIA associated with the "Other Gas" fuel code.