## Attachment C:

Evaluation of the Impact of Sandy Creek

Energy Station SO 2 

## Emissions

Contents:

Part 1: TCEQ ’s Evaluation of SO 2 

### Levels in McLennan County

Part 2: Additional Supporting Information for Sandy Creek

Power Station

## Attachment C, Part 1:

TCEQ’s Evaluation of SO 2 

### Levels in McLennan County

### TCEQ’s Evaluation of SO 2 

### 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 ( SO 2 ) emissions along with McLennan County SO 2 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 SO 2 NAAQS. Sandy Creek is the only major SO 2 emissions source identified by the United States Environmental Protection Agency ( EPA ) in McLennan County. Due to

McLenna n County monitoring data showing compliance, the TCEQ determined that SO 2 emissions from Sandy Creek Energy Station do not significantly impact attainment of the

2010 SO 2 NAAQS in McLennan and nearby c ounties.

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

SO 2 concentrations. The 2014 SO 2 design value for this station is 6 parts per billion ( ppb ) , which is well below the 75 ppb SO 2 NAAQS. Southerly winds prevail in the Waco
area. The SO 2 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 SO 2 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. T he modeling res ults pro vide additional evidence that the facility demonstrates compliance with the 2010 SO 2 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 SO 2 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 SO 2 concentrations. This a ttachment contains copies of the additional
informati on 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 SO 2 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

emi ssions data used was 4,954.8 tons.

• While the 2012 SO 2 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 C ourt on March 2, 2015, this emission data grossly overstates the actual SO 2 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 installedand 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 over

estimated 2012 emissions for Sandy Creek. Actual 2012 SO 2 emissions for the Sandy Creek Energy Station coal

- fired unit are estimated to be only about 26 tons. Actual
monitored SO 2 emissions data after the certification of the facility’s CEMS shows the

SO 2 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 Statio n is approved by EPA and used to determine the facility’s emissions for the time period requested, the 2012 SO 2 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 SO 2 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 SO 2 emissions.

• The coal

- fired utility boiler located at Sandy Creek Energy Station is equipped with a dry
FGD scrubber for SO 2 control. The unit is limited by permit to firing only low sulfur

subbitumino us coal with a sulfur content not to exceed 0.60 lb/MMBtu of heat input. The facility’s permit conditions not only limit SO 2 emissions on both a pound per hour and ton per year basis, but also on lb/MMBtu basis. The unit’s SO 2 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 SO 2 

## Emissions

Part 2:

Additional Supporting Information for

Sandy Creek Energy StationDate 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, 11 th 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. R eid Ha rvey , 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 U nit S01 while firing natural gas in lieu of using maximum potential concent rations 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 Sa ndy 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 dr y- low NO

x burners and uses overfire air and a Selective Catalytic Reduction system with ammonia injection to control NO

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

The facility natural gas supplier contract specif ies 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 a nalytical 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

. T he 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 dat e the unit recommence s commercial operation. SCEA intends to certify the boiler CEMS within this applicable

deadline.

U nder 40 CFR § 75.4(d), the facility is required to determine and report SO 2 concentration,

NO

x emission rate, CO 2 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 SO 2 (as defined in section 2.1.1.1 of 40

CFR Part 75, A ppendix A ), the maximum potential NO

x 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, A ppendix A , or the m aximum potential CO 2 concentration, as defined in section

2.1.3.1 of 40 CFR Part 75, A ppendix A ; or

(2) The conditional data validation provisions o f 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), u ntil the

CEMS is certified

, SCEA seeks approval to use one of the altern ate methodologies listed in the following section to determine and report SO 2 , NO

x , and CO 2 emission rates and unit heatPage 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 SO 2 , NO

x and CO 2 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 SO 2 emission factor provided in 40 CFR Part 75, Appendix F, Equation F-23 to calculate SO 2 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 boil er s, while still reporting conservative ly 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 SO 2 and CO 2 concentration values and pro

- rated stack flow in the missing data substitution procedure will

result in more conservative hourly emissions than the val ues obtained when using the alte rnate methodologies provided in Part 75 Appendix D and G for calculating SO 2 and CO 2 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 w as 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 bel ow.

Pipeline Natural Gas Firing Alternate Calculation Methodology 1: T he 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:

SO 2 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 avail able, i.e., 0.002 lb/MMBtu and a maximum CO 2 concentration of 7.9% as determined below.

NO

x emissions

– emission factor of 0.197 lb/MMBtu based on a maximum NO

x concentration of 1 00 ppm provided by the manufacturer and a minimum CO 2 concentration of

6.3% wet determined based on the minimum CO 2 concentration of 11.2% for coal and thePage 4

ratio of the carbon

- based F

- factors for natural gas and sub

- bituminous coal provided in the

rule

.

CO 2 emissions

– default maximum CO 2 concentration of 7.9% determined based on the

default maximum CO 2 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: T he 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 con centrations :

SO 2 emissions

– default SO 2 maximum concentration of 2.0 ppmv wet specified in 40 CFR §75.11(e)(iii) for very low sulfur fuels.

NO

x and CO 2 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 prepare d

and submit ted the 4 th Qtr 2012 report using the maximum coal values as required by 40 CFR §75.4(d)(1). However, SCEA respectfully requests that t he EPA CAMD hold off on performing the 2012 Acid Rain/CAIR reconciliation that beg an on March 1, 2013 for unit S01, until the petition is reviewed

, the necessary revisions are made to the se emission report s 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 PresidentACID 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 submitte d 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 com plete. 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 NO

x emission calculations were slightly modified to incorporate the minimum CO 2 wet concentration estimated based on the minimum CO 2 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 i nclude more realistic NO

x maximum emission rate s for coal and pipeline natural gas, estimated using

manufacturer NO

x MPC rather than Part 75 NO

x MPC default values for these fuels.

SO 2 Emissions

F or 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

SO 2 emissions calculations along with the maximum potential flow rate for coal combustion. As identified in the electronic monitoring plan provided in Attachment C, the c oal SO 2 MPC is 758.6 ppmv wet and the coal MPF is 134,058, 000 scfh. Since the SO 2 monitor measures on a wet basis, Equation F

- 1 from Appendix F of Part 75 will b e used to calculate the SO 2 emission

rate in lb/hr. The unit DAHS Part 75 software will calc ulate the coal SO 2 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 method ology will be used to calculate the SO 2 emissions for the natural gas combustion since the facility i s able to document that the gas meets the Part 72 definition of pipeline natural gas ( PNG ).

The maximum potential SO 2 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 equivalen t stack gas concentration, a modified version of Equation F

- 6 in Appendix F is used, where C h is the SO 2 concentration (ppm) , and the K factor is 1.660 x 10 -7 lb/scf -ppm SO 2 . The maximum potential

CO 2 concentration for PNG combustion must be used in this calculation. To obtain the CO 2 MPC for PNG, the coal

- fired MPC (i.e., 14% CO 2 , 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% CO 2

.

(MPC) PNG = (1040/1840) (14% CO 2 ) = 7.9% CO 2

Rearranging Equation F -6 and solving it for SO 2 concentration , the PNG SO 2 MPC is determined to be 0.9 ppmv wet.



# ( ) ( ) ( ) ( ) ( )

2 7 2 

### 9.0 )1040()1066.1(100 )9.7(002.0

100 % SOppm

x FK COE

c

c

h 

### = = =

−When a unit with an SO 2 monitor combusts natural gas, very low SO 2 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 SO 2 when PNG is combusted.

To det ermine the SO 2 mass emissions from PNG combustion in 2012 /2013, the facility

will substitute the SO 2 MPC and MPF into Equation F -1 to calculate the SO 2 emission rate in

lb/hr. The MPF for PNG combustion is less than the MPF for coal because the unit’s he at i nput 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

MM Btu/hr at normal CO 2 concentrations . The corresponding MPF for PNG a t 8

, 185 MM Btu/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 MM Btu /h r when PNG is combusted. T herefore, 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 SO 2 MPCs and the MPF determined above into Equation F

- 1, the two
alternate SO 2 emission rate s in lb/hr for PNG combustion would be:

E = K C SO2 Q = (1.66 x 10 -7 lb/scf -ppm) (0.9 ppm) (43,582,000 scfh)

E = 6.5 lb/hr

E = K C SO2 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 SO 2 emissions in tons using one of

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

CO 2 Emissions

For coal

- fired hours, Equation F

- 11 from Appendix F of Part 75 will be used to calculate

the CO 2 mass emission rate in tons/hr by substituting the coal MPF and maximum CO 2 default values specified above. The K

- factor to be used in the equati on is 5.7 x 10 - 7 tons/scf- %CO 2

. The unit DAHS Part 75 software will calculate the coal CO 2 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 v alue is 43,582,0 00 scfh and the MPC is 7.9% CO 2 , as determined above. This will result in a CO 2 mass emission rate of 196.2 tons/hr.

E CO2 = K (C CO2 ) (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 CO 2 emissions in tons using these maximum values and the actual unit operating hours firing PNG.

NO

x Emissions

Equation F

- 6 from Appendix F of Part 75 will be used to calculate the maximum potential NO

x emission rate in lb/MMBtu . In Equation F

- 6, the NO

x concentration must be the MPC, and the CO 2 concentration may either be th e minimum CO 2 during normal operation (excluding startup, shutdown, and upsets) or the diluent cap value.

For coal combustion, the NO

x MPC identified in the electronic monitoring plan is 600

ppm . This value was provided by the boiler manufacturer

. The minimum CO 2 concentration is

11.2% CO 2

. based on the minimum dry CO 2 concentration of 13.3 9% and maximum moisture

concentration of 16 .1 % used to estimate the MPF of 134,058,000 s cfh also identified in the electronic monitoring plan. Therefore, the max imum potential NO

x emission rate (MER) for

coal would be:

mmBtu lb x CO FCKE

c NOx /177.1 2.11 100 *1840*600*10194.1 %

100 7

2 =

= = −

For PNG combustion, in the absence of actual measured NO

x concentrations or manufacturer estimated NO

x MPC

, the facility would be required to use 600 ppm (default from

Tab le 2

- 1 in section 2.1.2.1 of Appendix A) as the NO

x MPC. To estimate the minimum CO 2 concentration for PNG combustion, the estimated minimum value for coal was multiplied by the

ratio of the carbon

- based F

- factors for natural gas a nd sub

- bituminous coal, i.e., 11.2 % CO 2 (1040/1840) = 6.3 % CO 2 . Therefore, the NO

x MER for PNG would be:

mmBtu lb x CO FCKE

c NOx /183.1 3.6 100 *1040*600*10194.1 %

100 7

2 =

= = −

This NO

x emission rate is grossly overstated (likely by a factor of 4 or more). In view of this the facility obtained quality- assured NO

x 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 NO

x MPC value and avoid substan tial over

- reporting of the NO

x mass emissions.

Based on the data provided in Attachment D, the PNG NO

x MPC would be 45 ppm. However, to be conservative, the facility will use in the calculations the NO

x MPC value of 100 ppm provided by the burner manufacturer (documentation also provided in Attachment D)

. Therefore, the more realistic NO

x MER for PNG would be:mmBtu lb x CO FCKE

c NOx /197.0 3.6 100 *1040*100*10194.1 %

100 7

2 =

= = −

The hourly NO

x mass emission rate in lb/hr will b e calculated using Equation F

- 24a in Appendix F (i.e., as the product of the NO

x emission rate and heat input rate). In this e quation,

the NO

x emission rate w ill be the fuel

- specific MER determined above and the heat input rate

w ill 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 NO

x maximum emission rate for coal an d

PNG combustion would be:

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

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

The unit DAHS Part 75 software will calculate the coal and PNG NO

x emissions in tons using

thes e 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