Attachment C: 

Evaluation of the Impact of Sandy Creek

Energy Station SO2 Emissions

Contents:

Part 1: TCEQ’s Evaluation of SO2 Levels in McLennan County 

Part 2: Additional Supporting Information for Sandy Creek 

Power Station

Attachment C, Part 1:

TCEQ’s Evaluation of SO2 Levels in McLennan County

TCEQ’s Evaluation of SO2 Levels in McLennan County

Sandy Creek Energy Station – McLennan County, TX

The Texas Commission on Environmental Quality (TCEQ) evaluated the impact of the Sandy 

Creek Energy Station sulfur dioxide (SO2) emissions along with McLennan County SO2

emissions with the use of monitoring data. Past and recent monitored data from the Waco 

Mazanec C1037 air quality monitor show McLennan County has been, and is still, attaining 

the 2010 SO2 NAAQS. Sandy Creek is the only major SO2 emissions source identified by the 

United States Environmental Protection Agency (EPA) in McLennan County. Due to 

McLennan County monitoring data showing compliance, the TCEQ determined that SO2

emissions from Sandy Creek Energy Station do not significantly impact attainment of the 

2010 SO2 NAAQS in McLennan and nearby counties. 

• The TCEQ has one monitor, Waco Mazanec C1037, in McLennan County that measures 

SO2 concentrations. The 2014 SO2 design value for this station is 6 parts per billion 

(ppb), which is well below the 75 ppb SO2 NAAQS. Southerly winds prevail in the Waco 

area. The SO2 monitor is located approximately 14 miles to the northwest of the Sandy 

Creek Energy Station. As a result, the Waco Mazanec monitor is downwind of the energy 

station in prevailing weather conditions. This indicates that the Sandy Creek Energy 

Station does not significantly impact attainment of the 2010 SO2 NAAQS in McLennan 

County or other counties downwind of the facility.

Sandy Creek Energy Station has submitted additional information, including its own 

modeling results, to EPA Region 6. The modeling results provide additional evidence that 

the facility demonstrates compliance with the 2010 SO2 NAAQS. Sandy Creek’s 

determination of compliance for the facility provides additional information in support of an 

attainment designation for McLennan County. 

• By letter dated June 12, 2015 to Ms. Wren Stenger of EPA Region 6, Sandy Creek Energy 

Station submitted information to the EPA for consideration in making designations for 

the 2010 SO2 NAAQS, including: copies of the site’s air quality permit; Sandy Creek 

Energy Station’s April 5, 2013 petition to the EPA Clean Markets Division for an 

Alternate Emissions Reporting Methodology; and a modeling analysis for one-hour 

average ambient SO2 concentrations. This attachment contains copies of the additional 

information submitted to the EPA by Sandy Creek in 2013 and 2015. 

Sandy Creek Energy Station should not have been included in the list of sites identified in 

the EPA’s March 20, 2015 letter. The 2012 SO2 emissions data for Sandy Creek Energy 

Station cited by the EPA is substituted emissions data, not actual measured data, and greatly 

over-estimates the emissions for the facility. Sandy Creek’s estimate of actual emissions, 

taking into account controls and actual conditions, is 25.6 tons, whereas the substituted 

emissions data used was 4,954.8 tons.

• While the 2012 SO2 emissions data for Sandy Creek Energy Station in the EPA Clean Air 

Markets Division’s Air Market Program Database is numerically over the threshold that 

the EPA agreed to in the consent decree approved by the Court on March 2, 2015, this 

emission data grossly overstates the actual SO2 emissions from the facility in 2012. The 

Sandy Creek Energy Station facility commenced operations on November 24, 2012; 

however, the unit’s continuous emissions monitoring system (CEMS) was not installed 
and certified until March 2013. In accordance with 40 Code of Federal Regulations 

(CFR) Part 75 monitoring requirements, Sandy Creek Energy State followed the specified 

data substitution requirements for reporting emissions to EPA from November 2012 

through March 2013. However, the data substitution requirements lead to greatly overestimated 2012 emissions for Sandy Creek. Actual 2012 SO2 emissions for the Sandy 

Creek Energy Station coal-fired unit are estimated to be only about 26 tons. Actual 

monitored SO2 emissions data after the certification of the facility’s CEMS shows the 

SO2 emission rate to be less than 0.1 pound per million British thermal units 

(lb/MMBtu), which is less than one-tenth the 1.137 lb/MMBtu determined from the 40 

CFR Part 75 substituted emissions data reported to the Air Markets Program for 2012.

• As allowed by 40 CFR Part 75, §75.4(d)(4), Sandy Creek Energy Station submitted a 

petition for an alternate methodology for reporting substituted emission data on April 5, 

2013 to Mr. Reid Harvey, Acting Director of the EPA Clean Air Markets Division. As far 

as the TCEQ is aware, the EPA has not yet acted on Sandy Creek Energy Station’s 

petition. If the alternate methodology proposed by Sandy Creek Energy Station is 

approved by EPA and used to determine the facility’s emissions for the time period 

requested, the 2012 SO2 emissions reported to the Air Markets Program would be an 

estimated 2,280 tons. This estimate still overstates emissions because the methodology

assumes maximum potential concentration (i.e., no SO2 pollution controls) and 

maximum potential flow rate for the 270 hours that the unit fired coal fuel. If the EPA 

had acted on Sandy Creek Energy Station’s petition and approved the proposed 

methodology in a timely manner, the reported 2012 emissions in the Air Markets 

Program Database would have been under the 2,600-ton threshold specified in the 

consent decree.

Sandy Creek Energy Station is a modern coal-fired power plant with a flue gas 

desulfurization (FGD) scrubber and stringent permit restrictions on SO2 emissions.

• The coal-fired utility boiler located at Sandy Creek Energy Station is equipped with a dry 

FGD scrubber for SO2 control. The unit is limited by permit to firing only low sulfur 

subbituminous coal with a sulfur content not to exceed 0.60 lb/MMBtu of heat input. 

The facility’s permit conditions not only limit SO2 emissions on both a pound per hour 

and ton per year basis, but also on lb/MMBtu basis. The unit’s SO2 emissions are limited 

to 0.10 lb/MMBtu on a 12-month rolling average basis and 0.12 lb/MMBtu on a 30-day 

rolling average basis.
Attachment C: 

TCEQ’s Evaluation of the Impact of Sandy Creek

Energy Station SO2 Emissions

Part 2:

Additional Supporting Information for

Sandy Creek Energy Station












































Date Run: 06/11/2015

EDSTM Enterprise version 9.1.17.2

Summary Operations Report

Start Date:    01/01/2012 00:00  

Stop Date:   12/31/2012 23:59

Total Hours Operated:   587

Total Hours Gas Firing:  587

Total Hours Coal Firing:  270

   


Sandy Creek Energy Associates, L.P. c/o LS Power Development, LLC

Two Tower Center, 11th Floor

East Brunswick, New Jersey 08816

(732) 249-6750 Tel.

(732) 249-7290 Fax.

File No. 20.1.2.1

 

 Via Certified Mail

 April 5, 2013 

Mr. Reid Harvey, Acting Director

Attn: Mr. Travis Johnson 

U.S. Environmental Protection Agency 

Clean Air Markets Division, MC-6204J 

1200 Pennsylvania Avenue, NW 

Washington, DC 20460 

Re: Petition for Approval of Alternate Emissions Reporting Methodology for Unit 

S01 at the Sandy Creek Energy Station (ORIS Code 56611) Pursuant to 40 CFR

§75.66(l) 

Letter No.: SCEA-EPA-0012 

Dear Mr. Harvey,

Sandy Creek Energy Associates, LP (SCEA) is submitting this petition pursuant to 40 CFR

§75.4(d)(4) and 40 CFR §75.66(l) to request authorization to use alternate methodologies for 

calculating and reporting emissions for Unit S01 while firing natural gas in lieu of using 

maximum potential concentrations and stack flow rate as specified in 40 CFR §75.4(d)(1) until 

the facility CEMS is certified. The use of maximum potential concentrations and stack flow 

rate based on coal firing grossly overestimates the natural gas emissions. 

Background 

The Sandy Creek Energy Station is owned and operated in part by SCEA. The facility has a 

pulverized coal boiler rated at a nominal 8,185 MMBtu/hr, designated as Unit S01, which is 

subject to the following programs: ARP, CAIRNOX and CAIRSO2. The unit started 

commercial operation on October 10, 2011 but was forced to shut down during the 

commissioning process due to a casualty event with the boiler. The unplanned shutdown 

notification was submitted to EPA CAMD on 11/8/2011 as specified in 40 CFR §75.61(a)(3). 

The pulverized coal boiler is designed to fire low-sulfur sub-bituminous Powder River Basin 

coal but uses pipeline quality natural gas as the startup fuel and for flame stabilization up to 

25% load. When operating on coal, the boiler is equipped with dry-low NOx burners and uses 

overfire air and a Selective Catalytic Reduction system with ammonia injection to control NOx

emissions and a spray dryer absorber with lime injection to control SO2 emissions. 
Page 2 

The facility natural gas supplier contract specifies that the gas will contain no more than 5 

grains of total sulfur per 100 standard cubic feet and that the gas heating value will be between 

950 and 1050 Btu/scf. Therefore, as allowed under 40 CFR Part 75, Appendix D, Section 

2.3.1.4(a)(3), the facility obtained and analyzed one representative sample of the gas fired in 

the boiler to determine its total sulfur content to be able to demonstrate that the gas initially 

qualifies as pipeline natural gas. The sample analytical result demonstrating that the total 

sulfur content of the gas is ≤ 0.5 grains/100scf is provided in Attachment A. In addition, the

facility obtained a result of the natural gas analyzed at the gas yard by the supplier gas 

chromatograph on the same day that the facility grab sample was taken (2/13/13) to 

demonstrate that the heating value is between 950 and 1100 Btu/scf. This information is also 

provided in Attachment A. 

Due to the forced outage required for boiler repair, the CEMS could not be certified within 180 

calendar days of the initial commercial operation date because Unit S01 could not be operated. 

The unit is now subject to the initial CEMS certification deadline and reporting requirements 

provided in 40 CFR §75.4(d). SCEA provided notification to EPA CAMD on November 14, 

2012 as specified in 40 CFR §75.61(a)(3)(ii) and the unit recommenced commercial operation 

on November 24, 2012. Under §75.4(d), the deadline for the initial CEMS certification is 

within 90 unit operating days or within 180 calendar days from the date the unit recommences 

commercial operation. SCEA intends to certify the boiler CEMS within this applicable

deadline.

Under 40 CFR §75.4(d), the facility is required to determine and report SO2 concentration, 

NOx emission rate, CO2 concentration, and flow rate data for all unit operating hours after the 

applicable compliance date until all of the required certification tests are successfully 

completed, using either: 

(1) The maximum potential concentration of SO2 (as defined in section 2.1.1.1 of 40 

CFR Part 75, Appendix A ), the maximum potential NOx emission rate, as defined in 40 

CFR §72.2 , the maximum potential flow rate, as defined in section 2.1.4.1 of 40 CFR 

§75, Appendix A, or the maximum potential CO2 concentration, as defined in section 

2.1.3.1 of 40 CFR Part 75, Appendix A; or 

(2) The conditional data validation provisions of 40 CFR §75.20(b)(3); or 

(3) Reference methods under 40 CFR §75.22(b); or

(4) Another procedure approved by the Administrator pursuant to a petition under 40 

CFR §75.66. 

The unit has operated on natural gas for numerous hours since it restarted its commissioning in 

November 2012. Consequently, pursuant to the requirements of 40 CFR §75.4(d)(4), until the 

CEMS is certified, SCEA seeks approval to use one of the alternate methodologies listed in the 

following section to determine and report SO2, NOx, and CO2 emission rates and unit heat 
Page 3 

input rate during the hours in which the boiler is fired only with natural gas, because these data 

would be more representative of the actual unit emissions than the maximum values required 

by 40 CFR Part 75, Appendix A which are based on coal rather than natural gas. 

Proposed Natural Gas Alternate Calculation Methodologies 

Part 75 requires coal-fired boilers, such as the Unit S01 at Sandy Creek Energy Station, to use 

CEMS and stack flow methodology to calculate SO2, NOx and CO2 emissions and heat input 

rate. In addition, Part 75 allows units that fire low sulfur gaseous fuel during startup to use the 

alternate methodology based on heat input and SO2 emission factor provided in 40 CFR Part 

75, Appendix F, Equation F-23 to calculate SO2 emissions when firing such fuels. 

In order to report emissions during periods of natural gas firing using the CEMS and stack 

methodology required for coal-fired boilers, while still reporting conservatively high but more 

representative emissions for the boiler , SCEA consulted with Mr. Robert Vollaro of EPA 

CAMD who provided guidance on which SCEA developed the alternate methodologies 

described below. It is anticipated that the use of these maximum default SO2 and CO2

concentration values and pro-rated stack flow in the missing data substitution procedure will 

result in more conservative hourly emissions than the values obtained when using the alternate 

methodologies provided in Part 75 Appendix D and G for calculating SO2 and CO2 emissions

from pipeline natural gas combustion. Documentation of how the default values were 

determined is provided in Attachment B. 

The maximum default values to be used while firing coal and/or coal and gas are the ones 

identified in the facility revised electronic monitoring plan that was submitted to EPA CAMD

on 3/26/13 and also documented in the calculations provided in Attachment B. These 

maximum values were determined as specified in 40 CFR Part 75, Appendix A. A printout of 

the electronic monitoring plan is provided in Attachment C. SCEA hereby requests EPA 

CAMD’s approval to use fuel specific missing data substitution procedures in order to be able 

to use the maximum default values for coal and gas separately until the CEMS is certified. The 

default values for coal will be used as specified in 40 CFR §75.4(d)(1) and the default values 

for gas will be used in one of the alternate emission calculations listed below. 

 

Pipeline Natural Gas Firing Alternate Calculation Methodology 1: The facility proposes 

to calculate the emissions using the maximum pro-rated stack flow of 43,582,000 scfh that 

corresponds to the maximum design heat input rate for the natural gas burner (3,000 

MMBtu/hr) and the following emission factors and/or concentrations: 

SO2 emissions – concentration of 0.9 ppmv wet derived from the emission factor 

provided in the rule (table D-6) for pipeline natural gas when fuel sulfur data is not available, 

i.e., 0.002 lb/MMBtu and a maximum CO2 concentration of 7.9% as determined below. 

NOx emissions – emission factor of 0.197 lb/MMBtu based on a maximum NOx

concentration of 100 ppm provided by the manufacturer and a minimum CO2 concentration of 

6.3% wet determined based on the minimum CO2 concentration of 11.2% for coal and the 
Page 4 

ratio of the carbon-based F-factors for natural gas and sub-bituminous coal provided in the 

rule. 

CO2 emissions – default maximum CO2 concentration of 7.9% determined based on the 

default maximum CO2 concentration for coal (14%) and the ratio of the carbon-based F-factors 

for natural gas (1040 dscf/mmBtu) and sub-bituminous coal (1840 dscf/mmBtu) provided in 

the rule. 

Pipeline Natural Gas Alternate Calculation Methodology 2: The facility proposes to

calculate the emissions using the maximum pro-rated stack flow of 43,582,000 scfh that 

corresponds to the maximum design heat input rate for the natural gas burner (3,000 

MMBtu/hr) and the following emission factors and/or concentrations: 

SO2 emissions – default SO2 maximum concentration of 2.0 ppmv wet specified in 40 

CFR §75.11(e)(iii) for very low sulfur fuels. 

NOx and CO2 emissions - will be calculated the same way as in methodology 1 based on 

guidance received from EPA CAMD.

Conclusion 

SCEA understands that the petition review process may take a few months and has prepared 

and submitted the 4th Qtr 2012 report using the maximum coal values as required by 40 CFR

§75.4(d)(1). However, SCEA respectfully requests that the EPA CAMD hold off on 

performing the 2012 Acid Rain/CAIR reconciliation that began on March 1, 2013 for unit S01, 

until the petition is reviewed, the necessary revisions are made to these emission reports and 

the revised reports are submitted to EPA CAMD. 

Should you have any questions or need any additional information to process this petition in a 

timely manner, please contact Bill Petersen at (254) 896-4317. 

Sincerely,

George Scienski

Vice President 
ACID RAIN CERTIFICATION STATEMENT

I am authorized to make this submission on behalf of the owners and operators of the source or 

units for which the submission is made. I certify under penalty of law that I have personally 

examined, and am familiar with, the statements and information submitted in this document and 

all its attachments. Based on my inquiry of those individuals with primary responsibility for 

obtaining the information, I certify that the statements and information are to the best of my 

knowledge and belief true, accurate, and complete. I am aware that there are significant penalties 

for submitting false statements and information or omitting required statements and information, 

including the possibility of fine or imprisonment. 

 04/05/2013 

______________________________________________ ____________________________ 

 Signature Designated Representative Date
ATTACHMENT A

PIPELINE NATURAL GAS TOTAL SULFUR 

DOCUMENTATION


ATTACHMENT B

COAL AND NATURAL GAS PROPOSED EMISSION 

CALCULATIONS
Proposed Emissions Calculations for Sandy Creek 

The calculation methodologies provided below were derived based on guidance received from 

Robert Vollaro of EPA CAMD. The NOx emission calculations were slightly modified to 

incorporate the minimum CO2 wet concentration estimated based on the minimum CO2 dry 

concentration of 13.39% and maximum moisture concentration of 16.1% used to estimate the 

MPF of 134,058,000 scfh identified in the electronic monitoring plan and to include more 

realistic NOx maximum emission rates for coal and pipeline natural gas, estimated using 

manufacturer NOx MPC rather than Part 75 NOx MPC default values for these fuels. 

SO2 Emissions

 For any hour(s) in which coal was combusted after the unit recommenced operation in 

November 2012 and before the CEMS is certified in 2013, the MPC for coal must be used in the 

SO2 emissions calculations along with the maximum potential flow rate for coal combustion. As 

identified in the electronic monitoring plan provided in Attachment C, the coal SO2 MPC is 

758.6 ppmv wet and the coal MPF is 134,058,000 scfh. Since the SO2 monitor measures on a 

wet basis, Equation F-1 from Appendix F of Part 75 will be used to calculate the SO2 emission 

rate in lb/hr. The unit DAHS Part 75 software will calculate the coal SO2 emissions in tons 

using these maximum values and the actual unit operating hours firing coal. 

For hours in which natural gas was combusted, the MPC for natural gas must also be 

used in the emissions calculations, along with the maximum potential flow rate for natural gas 

combustion. These values are significantly lower than the MPC and MPF for coal combustion. 

The following methodology will be used to calculate the SO2 emissions for the natural 

gas combustion since the facility is able to document that the gas meets the Part 72 definition of 

pipeline natural gas (PNG). 

The maximum potential SO2 emission rate for PNG combustion is 0.002 lb/MMBtu, 

according to Table D-6 in Appendix D of Part 75. To convert this to an equivalent stack gas 

concentration, a modified version of Equation F-6 in Appendix F is used, where Ch is the SO2

concentration (ppm) , and the K factor is 1.660 x 10-7 lb/scf-ppm SO2. The maximum potential 

CO2 concentration for PNG combustion must be used in this calculation. To obtain the CO2

MPC for PNG, the coal-fired MPC (i.e., 14% CO2, from Appendix A, section 2.1.3.1) was 

multiplied by the ratio of the carbon-based F-factors for natural gas and sub-bituminous coal 

resulting in a PNG MPC of 7.9% CO2. 

 

(MPC)PNG = (1040/1840) (14% CO2) = 7.9% CO2

Rearranging Equation F-6 and solving it for SO2 concentration, the PNG SO2 MPC is 

determined to be 0.9 ppmv wet. 

( ) ( )

( ) ( )

( )

7 2

2 9.0

)1040()1066.1(100

)9.7(002.0

100

% SOppm FK xCOE

c

c

h = = = − 
When a unit with an SO2 monitor combusts natural gas, very low SO2 concentrations 

(sometimes zero or even negative) are often recorded. Part 75 requires all readings below 2 ppm 

to be reported as 2 ppm. Therefore, another option (recommended by EPA CAMD) is to use 2 

ppm as the MPC for SO2 when PNG is combusted. 

To determine the SO2 mass emissions from PNG combustion in 2012/2013, the facility 

will substitute the SO2 MPC and MPF into Equation F-1 to calculate the SO2 emission rate in 

lb/hr. The MPF for PNG combustion is less than the MPF for coal because the unit’s heat input 

rate can only reach 3,000 MMBtu/hr on PNG, as opposed to 8,185 MMBtu/hr on coal. The coal 

MPF is 134,058,000 scfh, which corresponds to the maximum hourly heat input of 8,185 

MMBtu/hr at normal CO2 concentrations. The corresponding MPF for PNG at 8,185 MMBtu/hr 

can be approximated by the ratio of the dry-basis F-factors for PNG and sub-bituminous coal as 

indicated in the following equation: 

 (MPF)PNG = (134,058,000) (8710/9820) = 118,905,000 scfh 

However, the unit can only reach 3,000 MMBtu/hr when PNG is combusted. Therefore, the 

MPF must be multiplied by the ratio of 3,000 MMBtu/hr to 8,185 MMBtu/hr. In view of this, 

the appropriate MPF for PNG combustion is estimated to be: 

 (118,905,000) (3,000/8,185) = 43,582,000 scfh 

Substituting the PNG SO2 MPCs and the MPF determined above into Equation F-1, the two 

alternate SO2 emission rates in lb/hr for PNG combustion would be: 

 E = K CSO2 Q = (1.66 x 10-7 lb/scf-ppm) (0.9 ppm) (43,582,000 scfh) 

 E = 6.5 lb/hr 

 E = K CSO2 Q = (1.66 x 10-7 lb/scf-ppm) (2 ppm) (43,582,000 scfh) 

 E = 14.5 lb/hr 

The unit DAHS Part 75 software will calculate the PNG SO2 emissions in tons using one of 

these maximum values (whichever approved) and the actual unit operating hours firing PNG. 

CO2 Emissions

For coal-fired hours, Equation F-11 from Appendix F of Part 75 will be used to calculate 

the CO2 mass emission rate in tons/hr by substituting the coal MPF and maximum CO2 default 

values specified above. The K-factor to be used in the equation is 5.7 x 10-7 tons/scf-%CO2. 

The unit DAHS Part 75 software will calculate the coal CO2 emissions in tons using these 

maximum values and the actual unit operating hours firing coal. 
For PNG combustion, Equation F-11 will also be used, except that the MPF value is 

43,582,000 scfh and the MPC is 7.9% CO2, as determined above. This will result in a CO2 mass 

emission rate of 196.2 tons/hr. 

 ECO2 = K (CCO2) (Q) = (5.7 x 10-7) (7.9) (43,582,000) = 196.2 tons/hr 

This emission rate is higher than the one that would be obtained from Appendix G, but it is 

preferred because it uses CEMS-based concepts and a CEMS equation. The unit DAHS Part 75 

software will calculate the PNG CO2 emissions in tons using these maximum values and the 

actual unit operating hours firing PNG. 

NOx Emissions

Equation F-6 from Appendix F of Part 75 will be used to calculate the maximum 

potential NOx emission rate in lb/MMBtu. In Equation F-6, the NOx concentration must be the 

MPC, and the CO2 concentration may either be the minimum CO2 during normal operation 

(excluding startup, shutdown, and upsets) or the diluent cap value. 

For coal combustion, the NOx MPC identified in the electronic monitoring plan is 600 

ppm. This value was provided by the boiler manufacturer. The minimum CO2 concentration is 

11.2% CO2 .based on the minimum dry CO2 concentration of 13.39% and maximum moisture 

concentration of 16.1% used to estimate the MPF of 134,058,000 scfh also identified in the 

electronic monitoring plan. Therefore, the maximum potential NOx emission rate (MER) for 

coal would be: 

x lb mmBtu

CO NOx FCKE c /177.12.11

100 *1840*600*10194.1

%

100 7

2

= = = − 

For PNG combustion, in the absence of actual measured NOx concentrations or 

manufacturer estimated NOx MPC, the facility would be required to use 600 ppm (default from 

Table 2-1 in section 2.1.2.1 of Appendix A) as the NOx MPC. To estimate the minimum CO2

concentration for PNG combustion, the estimated minimum value for coal was multiplied by the

ratio of the carbon-based F-factors for natural gas and sub-bituminous coal, i.e., 11.2% CO2

(1040/1840) = 6.3% CO2. Therefore, the NOx MER for PNG would be: 

x lb mmBtu

CO NOx FCKE c /183.1

3.6

100 *1040*600*10194.1

%

100 7

2

= = = −

This NOx emission rate is grossly overstated (likely by a factor of 4 or more). In view of this the 

facility obtained quality-assured NOx concentration data from the CEMS while the unit was 

combusting only PNG during the period of 2/16/13 through 3/22/13, to determine a more 

realistic NOx MPC value and avoid substantial over-reporting of the NOx mass emissions. 

Based on the data provided in Attachment D, the PNG NOx MPC would be 45 ppm. However, 

to be conservative, the facility will use in the calculations the NOx MPC value of 100 ppm 

provided by the burner manufacturer (documentation also provided in Attachment D). 

Therefore, the more realistic NOx MER for PNG would be: 

 
x lb mmBtu

CO NOx FCKE c /197.03.6

100 *1040*100*10194.1

%

100 7

2

= = = −

The hourly NOx mass emission rate in lb/hr will be calculated using Equation F-24a in 

Appendix F (i.e., as the product of the NOx emission rate and heat input rate). In this equation, 

the NOx emission rate will be the fuel-specific MER determined above and the heat input rate 

will be the maximum rated hourly heat input calculated based on each fuel MPF and CO2 MPC 

identified above using Equation F-15. These calculated heat input rates will be conservatively 

higher than the maximum design heat input rate for the gas burner (i.e., 3,000 MMBtu/hr) and 

coal-fired boiler (i.e., 8,185 MMBtu/hr). 

Using the MER values calculated above, the hourly NOx maximum emission rate for coal and 

PNG combustion would be: 

Coal: 1.177 lb/MMBtu x 10200.1 MMBtu/hr = 12,006 lb/hr 

 

 PNG: 0.197 lb/MMBtu x 3310.6 MMBtu/hr = 652 lb/hr 

The unit DAHS Part 75 software will calculate the coal and PNG NOx emissions in tons using 

these maximum values and the actual unit operating hours firing each fuel. 
ATTACHMENT C

PRINTOUT OF ELECTRONIC MONITORING 

PLAN







ATTACHMENT D

FACILITY 2013 NOx CEMS DATA and GAS 

BURNER MANUFACTURER NOx MPC ESTIMATE