Navajo Nation Environmental Protection Agency –Air Quality Control/Operating Permit Program

Post Office Box 529, Fort Defiance, AZ 86504  Bldg. #2837 Route 112

Telephone (928) 729-4096, Fax (928) 729-4313, Email airquality@navajo-nsn.gov

www.navajonationepa.org/airquality.html

TITLE V PERMIT TO OPERATE

PERMIT #: FACILITY NAME: LOCATION: COUNTY: STATE:

NN-OP-15-06 NAVAJO GENERATING STATION PAGE COCONINO AZ

ISSUE DATE: EXPIRATION DATE: AFS PLANT ID: PERMITTING AUTHORITY:

XX/XX/2015 XX/XX/2020 04-005-N0423 NNEPA

ACTION/STATUS: PART 71 OPERATING PERMIT RENEWAL ISSUANCE

Robert K. Talbot, Plant Manager

Navajo Generating Station

P.O. Box 850

Page, Arizona 86040

Re: Issuance of Title V Operating Permit Renewal to Navajo 

Generating Station

Dear Mr. Talbot:

In accordance with the provisions of Title V of the Clean Air Act; 40 CFR Part 71; 

Navajo Nation Operating Permit Regulations §§ 404, 405(C)-(E), and subpart VI; 2004 

Delegation Agreement § VI(1) and (7); 2006 Supplemental Delegation Agreement; and all other 

applicable rules and regulations, the Permittee, Navajo Generating Station, is authorized to 

operate air emission units and to conduct other air pollutant-emitting activities in accordance 

with the permit conditions listed in this permit. 

Terms and conditions not otherwise defined in this permit have the same meaning as 

assigned to them in the referenced regulations. All terms and conditions of the permit are 

enforceable under the Clean Air Act by U.S. EPA, as well as by persons as defined in the Clean 

Air Act, and by NNEPA only as provided in the May 2005 Voluntary Compliance Agreement 

(VCA) between the Salt River Project, Arizona Public Service Company, and Navajo Nation. 

This permit is valid for a period of five (5) years and shall expire at midnight on the date 

five (5) years after the date of issuance unless a timely and complete renewal application has 

been submitted at least 6 months but not more than 18 months prior to the date of expiration. The 

permit number cited above should be referenced in future correspondence regarding this facility.

 

Date Dr. Donald Benn

Executive Director

Navajo Nation Environmental Protection Agency

THE NAVAJO NATION RUSSELL BEGAYE PRES I DENT

JONATHAN NEZ VICE PRESIDENT
Page 2 of 62

Abbreviations and Acronyms

Administrator Administrator of the U.S. EPA

AR Acid Rain

ARP Acid Rain Program

BART Best Available Retrofit Technology

CAA Clean Air Act [42 U.S.C. Section 7401 et seq.]

CEMS Continuous Emission Monitoring System

CFR Code of Federal Regulations

COMS Continuous Opacity Monitoring System

DC Dust Collector

ESP Electro Static Precipitator

FGD Flue Gas Desulfurization

gal gallon

HAP Hazardous Air Pollutant

hr hour

lb pound

LNB/SOFA Low-NOX Burner (LNB) and Separated Overfire Air (SOFA) system

MACT Maximum Achievable Control Technology

MVAC Motor Vehicle Air Conditioner

Mg megagram

MMBtu million British Thermal Units

MW Megawatts

mo month

NESHAP National Emission Standards for Hazardous Air Pollutants

NMHC Nonmethane Hydrocarbons

NNEPA Navajo Nation Environmental Protection Agency

NNOPR Navajo Nation Operating Permit Regulations

NOX Nitrogen Oxides

NSPS New Source Performance Standards

NSR New Source Review

PM Particulate Matter

PM-10 Particulate matter less than 10 microns in diameter

ppm parts per million

PSD Prevention of Significant Deterioration

PTE Potential to Emit

QIP Quality Improvement Plan

RHR Regional Haze Rule

RMP Risk Management Plan

SNAP Significant New Alternatives Program

SO2 Sulfur Dioxide

US EPA United States Environmental Protection Agency

VCA Voluntary Compliance Agreement

VOC Volatile Organic Compounds
Page 3 of 62

TABLE OF CONTENTS

Cover Page

Abbreviations and Acronyms

I. Source Identification

II. Requirements for Specific Units

A. Federal Implementation Plan Requirements

B. PSD Permit Requirements

C. Acid Rain Requirements

D. Visibility Federal Implementation Plan Requirements

E. NSPS General Provisions 

F. NSPS for Nonmetallic Mineral Processing Plants, 40 CFR Part 60, Subpart OOO

Requirements

G. Monitoring and Testing Requirements to Comply with NSPS for Nonmetallic Mineral 

Processing Plants, 40 CFR Part 60, Subpart OOO

H. NSPS for Stationary Compression Ignition Internal Combustion Engines, 40 CFR 

Part 60, Subpart IIII Requirements

I. NESHAP General Provisions

J. NESHAP for Coal- and Oil-Fired Electric Utility Steam Generating Units, 40 CFR 

Part 63, Subpart UUUUU Requirements

K. NESHAP for Industrial, Commercial, and Institutional Boilers and Process Heaters, 

40 CFR Part 63, Subpart DDDDD Requirements

L. NESHAP for Stationary Reciprocating Internal Combustion Engines, 40 CFR Part 63, 

Subpart ZZZZ Requirements

M. PM CEM Requirements

N. CAM Requirements

O. Requirements for Reagent Handling Systems

P. Operational Flexibility

III. Facility-Wide or Generic Permit Conditions

A. Testing Requirements

B. Recordkeeping Requirements

C. Reporting Requirements

D. Protection of Stratospheric Ozone

E. Asbestos from Demolition and Renovation

F. Compliance Schedule

IV. Title V Administrative Requirements

A. Fee Payment

B. Blanket Compliance Statement

C. Compliance Certifications

D. Duty to Provide and Supplement Information

E. Submissions

F. Severability Clause

G. Permit Actions
Page 4 of 62

H. Administrative Permit Amendments 

I. Minor Permit Modifications

J. Group Processing of Minor Permit Amendments

K. Significant Modifications 

L. Reopening for Cause

M. Property Rights

N. Inspection and Entry

O. Emergency Provisions

P. Transfer of Ownership or Operation

Q. Off Permit Changes

R. Permit Expiration and Renewal

S. Additional Permit Conditions 

T. Part 71 Permit Enforcement

Attachment A – Dust Control Plan

Attachment B – Phase II Acid Rain Permit Renewal

Attachment C – NESHAP for Coal- and Oil-Fired Electric Utility Steam Generating Units, 40 

CFR Part 63, Subpart UUUUU - Compliance, Monitoring, Testing, 

Notification, Recordkeeping, and Reporting Requirements
Page 5 of 62

I. Source Identification

 Managing Participant Name: Salt River Project Agricultural Improvement 

and Power District (SRP)*

 Managing Participant Mailing Address: P.O. Box 52025, PAB 352

Phoenix, Arizona 85072-2025

*Note: This facility is co-owned by 6 entities. SRP is listed as the managing participant in 

this permit since it acts as the facility operator and has accepted the responsibility to 

obtain environmental permits for Navajo Generating Station, including an Acid Rain 

permit and Part 71 Permit. In addition to SRP, the other 5 co-owners of this facility are:

1. U.S. Bureau of Reclamation (USBR) 

2. Los Angeles Department of Water and Power (LADWP) 

3. Arizona Public Service Company (APS) 

4. Nevada Power Company (NPC) 

5. Tucson Electric Power (TEP) 

 Plant Name: Navajo Generating Station

 Plant Location: 5 miles east of Page, AZ off U.S. Highway 98

Page, Arizona 

 County: Coconino, Arizona

 EPA Region: 9

 Reservation: Navajo Nation

 Tribe: Navajo

 Company Contact: Paul Ostapuk Phone: (928) 645-6577

Barbara Cenalmor Phone: (602) 236-2322

 Responsible Official: Robert K. Talbot Phone: (928) 645-6217

 EPA Contact: Geoffrey Glass Phone: (415) 972-3498

 Tribal Contacts: Eugenia Quintana Phone: (928) 871-7800

Tennille Begay Phone: (928) 729-4248 

 SIC Code: 4911

 AFS Plant Identification Number: 04-005-N0423

 Description of Process: The facility is 2,250 Net Megawatt coal-fired power plant.
Page 6 of 62

 Significant Emission Units:

Unit ID/

Stack ID

Unit Description Maximum 

Capacity

Commenced 

Construction 

Date

Control Method

U1/

Stack S1

One (1) pulverized coal-fired boiler,

using No. 2 fuel oil for ignition fuel. Stack S1 is 

equipped with SO2, NOX, CO, and PM CEMS 

and a COMS.

7,410 MBtu/hr;

750 Net MW 1970

ESP1; FGD system 

SCBR1 (1999); 

LNB/SOFA*(2011);

Sorbent Injection (2015)

U2/

Stack S2

One (1) pulverized coal-fired boiler,

using No. 2 fuel oil for ignition fuel. Stack S1 is 

equipped with SO2, NOX, CO, and PM CEMS 

and a COMS.

7,410 MBtu/hr;

750 Net MW 1970

ESP2; FGD system 

SCBR2 (1998); 

LNB/SOFA*(2010); 

Sorbent Injection (2015)

U3/

Stack S3

One (1) pulverized coal-fired boiler,

using No. 2 fuel oil for ignition fuel. Stack S1 is 

equipped with SO2, NOX, CO, and PM CEMS 

and a COMS.

7,410 MBtu/hr;

750 Net MW 1970

ESP3; FGD system 

SCBR3 (1997); 

LNB/SOFA*(2009);

Sorbent Injection (2015)

AUX A One (1) auxiliary boiler;

using No. 2 fuel oil as fuel 308 MMBtu/hr 1970 N/A

AUX B One (1) auxiliary boiler;

using No. 2 fuel oil as fuel 308 MMBtu/hr 1970 N/A

Coal Handling Operations

CT1 One (1) railcar unloading operation 10,000 tons/hr 1970 wet suppression

L1 - L12 Twelve (12) hopper feeders 2,400 tons/hr

(total) 1970 wet suppression

BC-1 through 

BC-4

Four (4) conveyors to the yard surge bin 1,800 tons/hr

(each) 1970 DC-8

BC-4A One (1) conveyor to the batch weight system 100 tons/hr 1970 DC-8

BFD-5A, 

BC-5

Two (2) reclaim conveyors 1,800 tons/hr

(each) 1970 DC-8

BC-6 One (1) conveyor to the yard surge bin 1,500 tons/hr 1970 DC-8

BC-6A through 

BC-6C Three (3) conveyors to the stacker/reclaimer 1,800 tons/hr(each) 1970 wet suppression/ enclosure

BC-7

One (1) conveyor to the emergency reclaim 

hopper 1,500 tons/hr 1970 wet suppression

YSB-1 One (1) yard surge bin 1,800 tons/hr 1970 DC-8

BC-8A, 

BC-8B Two (2) conveyors to plant surge bin 1,500 tons/hr(each) 1970 DC-8

BC-8AS, 

BC-8BS

Two (2) screens 1,500 tons/hr

(each) 1970 DC-8

PSB-1 One (1) plant surge bin 3,000 tons/hr 1970 DC-5

BC-9A,

BC-9B

Two (2) conveyors to the coal silos for boilers 

U1 and U2

1,500 tons/hr

(each) 1970 DC-5

BC-10A,

BC-10B

Two (2) conveyors to the coal silos for boiler 

U3

1,500 tons/hr

(each) 1970 DC-5

CC-1A through 

CC-9A; CC-1B 

through CC-9B

Three (3) enclosed cascading conveying systems 

to the coal storage silos for boilers U1, U2, and 

U3

1,500 tons/hr

(each) 1970 DC-1 through DC-4, DC-6, and DC-7

Silos 1A through 

1G Seven (7) storage silos for boiler U1 3,000 tons/hr(each) 1970 DC-1, DC-2, and baghouse PR-1.

Silos 2A through 

2G Seven (7) storage silos for boiler U2 3,000 tons/hr(each) 1970 DC-3, DC-4, and baghouse PR-2.

Silos 3A through 

3G Seven (7) storage silos for boiler U3 3,000 tons/hr(each) 1970 DC-6, DC-7, and baghouse PR-3.
Page 7 of 62

Unit ID/

Stack ID

Unit Description Maximum 

Capacity

Commenced 

Construction 

Date

Control Method

CS Outdoor coal storage piles 3,300 tons/hr

(total) 1970 wet suppression

Limestone Handling System Associated with the FGD Systems

Unloading Bay 

A and B Two (2) truck unloading operations 38 tons/hr(each) 1997 N/A

O-LSH-HOP-A One (1) limestone unloading hopper 300 tons/hr 1997 DC-9

O-LSH-HOP-B One (1) limestone unloading hopper 300 tons/hr 1997 DC-10

O-LSH-FDR-A One (1) conveyor 300 tons/hr 1997 DC-9

O-LSH-FDR-B One (1) conveyor 300 tons/hr 1997 DC-10

O-LSH-CNV-A One (1) conveyor 300 tons/hr 1997 DC-9

O-LSH-CNV-B One (1) conveyor 300 tons/hr 1997 DC-10

O-LSH-SILO-A 

and B Two (2) limestone storage silos 300 tons/hr(each) 1997 DC-11

O-LSP-FDR-A 

and B

Two (2) enclosed feeders to the slurry 

preparation system

36 tons/hr

(each) 1997 N/A

O-LSP-CNV-A 

and B Two (2) enclosed cleanout conveyors 5 tons/hr(each) 1997 N/A

O-LSP-MILL-A 

and B Two (2) ball mills 36 tons/hr(each) 1997 N/A

LS Limestone storage piles 600 tons/hr

(total) 1997 wet suppression

Fly Ash Handling System

Silo 1 One (1) fly ash bin for boilers U1 and U2 46 tons/hr 1970 DC-S1/2

Silo 2 One (1) fly ash bin for boiler U3 46 tons/hr 1970 DC-S3

Silo 1 and 2 

Loading

Two (2) partially enclosed fly ash truck loading 

operations

38 tons/hr

(each) 1970 DC-S1/2 and DC-S3

DWB-A through 

DWB-F

Six (6) bottom ash truck loading operations.

The bottom ash is processed in a wet form

46 tons/hr

(each) 1970 wet suppression

Soda Ash/Lime Handling Systems

SAB-1A, SAB2A, SAB-1B, 

SAB-2B

Four (4) soda ash storage bins 0.4 tons/hr 

(each) 1970 dust collector BH-6

LB-1 and LB-2 Two (2) lime storage bins 0.57 tons/hr 

(each) 1970 dust collector BH-7

Reagent Handing Systems

PAC Silo A Power active carbon (PAC) storage silo 40 tons 2015 integral baghouse

PAC Silo B PAC storage silo 40 tons 2015 integral baghouse

Fugitive-PAC Truck traffic on unpaved roads for PAC delivery 30 VMT/yr** 2015 water spray

Fugitive-CaBr2 Truck traffic on unpaved roads for Calcium 

Bromide delivery 365 VMT/yr** 2015 water spray

Miscellaneous Operations

Six (6) cooling towers 813,000 gal/min

(total) 1970 N/A

TR Fugitive emissions from unpaved roads N/A 1970 wet suppression

Note: (*) LNB/SOFA = Low-NOX burner (LNB) and Separated Overfire Air (SOFA) system.

 (**) VMT = vehicle miles traveled.
Page 8 of 62

II. Requirements for Specific Units

II.A. Federal Implementation Plan Requirements. The following requirements apply to 

coal-fired boilers U1, U2, and U3, coal and ash handling equipment, and the two 

auxiliary steam boilers at Navajo Generating Station. [40 CFR § 49.5513]

1. Definitions. The following definitions apply to Section II.A of this permit 

[40 CFR § 49.5513(c)]:

a. Absorber upset transition period means the 24-hour period following an 

upset of an SO2 absorber module which resulted in the absorber being 

taken out of service.

b. Affirmative defense means, in the context of an enforcement proceeding, a 

response or defense put forward by a defendant, regarding which the 

defendant has the burden of proof, and the merits of which are 

independently and objectively evaluated in a judicial or administrative 

proceeding. 40 CFR § 49.5513provides an affirmative defense to 

actions for penalties brought for excess emissions that arise 

during certain malfunction episodes.

c. Malfunction means any sudden and unavoidable failure of air pollution 

control equipment or process equipment or of a process to operate in a 

normal or usual manner. Failures that are caused entirely or in part by poor 

maintenance, careless operation, or any other preventable upset 

condition or preventable equipment breakdown shall not be 

considered malfunctions. An affirmative defense is not available if 

during the period of excess emissions, there was an exceedance of the 

relevant ambient air quality standard that could be attributed to the 

emitting source.

d. Plant-wide means a weighted average of particulate matter and SO2

emissions for boilers U1, U2, and U3 based on the heat input to each 

unit as determined by 40 CFR Part 75.

e. Point source means any crusher, any conveyor belt transfer point, any 

pneumatic material transferring, any baghouse or other control devices 

used to capture dust emissions from loading and unloading, and any other 

stationary point of dust that may be observed in conformance with 

Method 9 of Appendix A-4 of 40 CFR Part 60 (excluding stockpiles).

f. Regional Administrator means the Regional Administrator of the 

Environmental Protection Agency, Region 9, or his/her authorized 

representative.

g. Startup means the period from the start of fires in the boiler with fuel oil, 
Page 9 of 62

to the time when the electrostatic precipitator is sufficiently heated such 

that the temperature of the air preheater inlet reaches 400 degrees 

Fahrenheit and when a unit reaches 300 MW net load. Proper startup 

procedures shall include energizing the electrostatic precipitator prior to 

the combustion of coal in the boiler. 40 CFR § 49.5513 provides an 

affirmative defense to actions for penalties brought for excess emissions 

that arise during startup episodes. An affirmative defense is not available 

if during the period of excess emissions, there was an exceedance of the 

relevant ambient air quality standard that could be attributed to the 

emitting source.

h. Shutdown means the time that begins when the unit drops below 300 

MW net load with the intent to remove the unit from service. The 

precipitator shall be maintained in service until boiler fans are 

disengaged. 40 CFR § 49.5513 provides an affirmative defense to 

actions for penalties brought for excess emissions that arise during 

shutdown episodes. An affirmative defense is not available if during the 

period of excess emissions, there was an exceedance of the relevant 

ambient air quality standard that could be attributed to the emitting 

source.

i. Oxides of nitrogen (NOX) means the sum of nitrogen oxide (NO) and 

nitrogen dioxide (NO2) in the flue gas, expressed as nitrogen dioxide.

2. Emissions Limitations and Control Measures [40 CFR § 49.5513(d)]:

a. Sulfur oxides (SO2). The permittee shall not discharge or cause the 

discharge of sulfur oxides into the atmosphere from boilers U1, U2 and 

U3in excess of 1.0 pound per million British thermal units 

(lb/MMBtu) averaged over any three (3) hour period, on a plant-wide 

basis.

b. Particulate matter (PM). The permittee shall not discharge or cause the 

discharge of particulate matter into the atmosphere in excess of 0.060 

lb/MMBtu, on a plant-wide basis, as averaged from at least three sampling 

runs per stack, each at a minimum of 60 minutes in duration, each 

collecting a minimum sample of 30 dry standard cubic feet.

c. Dust. The permittee shall operate and maintain the existing dust suppression 

methods for controlling dust from the coal handling and storage 

facilities. A dust control plan was submitted by the permittee on June 

4, 2010 in accordance with 40 CFR § 49.5513(d)(3). A revised plan 

was submitted on February 2, 2015 and is attached as Attachment A

to this permit. The permittee shall not emit dust with an opacity greater 

than 20% from any crusher, grinding mill, screening operation, belt conveyor, 

truck loading or unloading operation, or railcar unloading station, as 
Page 10 of 62

determined using 40 CFR Part 60, Appendix A-4, Method 9.

d. Opacity. The permittee shall not discharge or cause the discharge of

emissions from the stacks of boilers U1, U2, or U3 into the 

atmosphere exhibiting greater than 20% opacity, excluding condensed 

uncombined water droplets, averaged over any six (6) minute period and 

40% opacity, averaged over six (6) minutes, during absorber upset 

transition periods.

3. Testing and Monitoring [40 CFR § 49.5513(e)]:

a. The permittee shall maintain and operate Continuous Emissions 

Monitoring Systems (CEMS) for NOX and SO2 and Continuous Opacity 

Monitoring Systems (COMS) on boilers U1, U2, and U3 in accordance 

with 40 CFR §§ 60.8 and 60.13(e), (f), and (h), and Appendix B of 40 

CFR Part 60. The permittee shall comply with the quality assurance 

procedures for CEMS and COMS found in 40 CFR part 75.

b. The permittee shall conduct annual mass emissions tests for particulate 

matter on boilers U1, U2, and U3, operating at rated capacity, using coal 

that is representative of that normally used. The tests shall be 

conducted using the appropriate test methods in 40 CFR Part 60, 

Appendix A.

c. During any calendar year in which an auxiliary boiler is operated for 720 

hours or more, and at other times as requested by the Administrator, the 

permittee shall conduct mass emissions tests for sulfur dioxide, nitrogen 

oxides and particulate matter on the auxiliary steam boilers, operating at 

rated capacity, using oil that is representative of that normally used. The 

tests shall be conducted using the appropriate test methods in 40 CFR Part 

60, Appendix A. For particulate matter, testing shall consist of three test 

runs. Each test run shall be at least sixty (60) minutes in duration and shall 

collect a minimum volume of thirty (30) dry standard cubic feet.

d. The permittee shall maintain two sets of opacity filters for each type of 

COMS, one set to be used as calibration standards and one set to be used 

as audit standards. At least one set of filters shall be on site at all times.

e. All emissions testing and monitor evaluation required pursuant to 40 

CFR § 49.5513(e)shall be conducted in accordance with the appropriate 

method found in 40 CFR Part 60, Appendices A and B.

f. The permittee shall install, maintain and operate ambient monitors at Glen 

Canyon Dam for particulate matter (PM2.5 and PM10), nitrogen dioxide, 

sulfur dioxide, and ozone. Operation, calibration and maintenance of the 

monitors shall be performed in accordance with 40 CFR Part 58, 
Page 11 of 62

manufacturer’s specification, and “Quality Assurance Handbook for Air 

Pollution Measurements Systems”, Volume II, U.S. EPA as applicable to

single station monitors. Data obtained from the monitors shall be reported 

annually to the Regional Administrator. All particulate matter samplers 

shall operate at least once every six days, coinciding with the national 

particulate sampling schedule.

g. Nothing herein shall limit EPA's ability to ask for a test at any time under 

section 114 of the Clean Air Act, 42 U.S.C. § 7414, and enforce against any 

violation of the Clean Air Act or this section.

h. A certified EPA Reference Method 9 of Appendix A-–4 of 40 CFR Part 60 

observer shall conduct a weekly visible emission observation for the 

equipment and activities described under Condition II.A.2.c. If visible 

emissions are present at any of the equipment and/or activities, a 6-minute 

EPA Reference Method 9 observation shall be conducted. The name of the 

observer, date and time of observation, results of the observations, and 

any corrective actions taken shall be noted in a log.

4. Reporting and Recordkeeping Requirements [40 CFR § 49.5513(f)]:

Unless otherwise stated all requests, reports, submittals, notifications and other 

communications to the Regional Administrator required by this section shall be 

submitted to the Director, Navajo Nation Environmental Protection Agency, 

P.O. Box 339, Window Rock, Arizona 86515, (928) 871-7692, (928) 871-7996 

(facsimile), and to the Director, Air Division, U.S. Environmental Protection 

Agency, Region IX, to the attention of Mail Code: AIR-5, at 75 Hawthorne Street, 

San Francisco, California 94105, (415) 972-3990, (415) 947-3579 (facsimile). 

For each unit subject to the emissions limitations in this section the permittee

shall:

a. Comply with the notification and recordkeeping requirements for testing 

found in 40 CFR § 60.7. All data/reports of testing results shall be 

submitted to the Regional Administrator and postmarked within 60 days 

of testing.

b. For excess emissions, notify the Navajo Nation Environmental Protection 

Agency Director by telephone or in writing and the U.S. 

Environmental Protection Agency Regional Administrator by 

telephone, in writing or by email (AEO_R9@epa.gov) within one business 

day. A complete written report of the incident shall be submitted to the 

Regional Administrator within ten (10) working days after the event. 

This notification shall include the following information:

(i) The identity of the stack and/or other emissions points where

excess emissions occurred;

(ii) The magnitude of the excess emissions expressed in the units of 
Page 12 of 62

the applicable emissions limitation and the operating data and 

calculations used in determining the magnitude of the excess 

emissions;

(iii) The time and duration or expected duration of the excess 

emissions;

(iv) The identity of the equipment causing the excess emissions;

(v) The nature and cause of such excess emissions;

(vi) If the excess emissions were the result of a malfunction, the steps 

taken to remedy the malfunction and the steps taken or planned to 

prevent the recurrence of such malfunction; and

(vii) The steps that were taken or are being taken to limit excess 

emissions.

c. Notify the Regional Administrator verbally within one business day of

determining that an exceedance of the NAAQS has been measured by a 

monitor operated in accordance with this regulation. The notification to 

the Regional Administrator shall include the time, date, and location of the 

exceedance and the pollutant and concentration of the exceedance. 

Compliance with Condition II.A.4.c.v shall not excuse or otherwise 

constitute a defense to any violations of this section or of any law or 

regulation which such excess emissions or malfunction may cause. The 

verbal notification shall be followed within fifteen (15) days by a letter 

containing the following information:

(i) The time, date, and location of the exceedance;

(ii) The pollutant and concentration of the exceedance;

(iii) The meteorological conditions existing 24 hours prior to and 

during the exceedance;

(iv) For a particulate matter exceedance, the 6-minute average opacity 

monitoring data greater than 20% for the 24 hours prior to and 

during the exceedance; and

(v) Proposed plant changes such as operation or maintenance, if any, 

to prevent future exceedances.

d. Submit quarterly excess emissions reports for sulfur dioxide and 

opacity as recorded by CEMS and COMS together with a CEMS data 

assessment report to the Regional Administrator no later than 30 days 

after each calendar quarter. The permittee shall complete the excess 

emissions reports according to the procedures in 40 CFR § 60.7(c) and 

(d) and include the Cylinder Gas Audit. Excess opacity due to 

condensed water vapor in the stack does not constitute a reportable 

exceedance; however, the length of time during which water vapor 

interfered with COMs readings should be summarized in the 40 CFR § §
Page 13 of 62

60.7 (c) report.

5. Compliance Certifications [40 CFR § 49.5513(g)]:

Notwithstanding any other provision in this permit, the permittee may use any 

credible evidence or information relevant to whether a source would have 

been in compliance with applicable requirements if the appropriate 

performance or compliance test had been performed, for the purpose of 

submitting compliance certifications.

6. Equipment Operations [40 CFR § 49.5513(h)]:

The permittee shall operate all equipment or systems needed to comply with this 

section in accordance with 40 CFR § 60.11(d) and consistent with good 

engineering practices to keep emissions at or below the emissions limitations in 

this section, and following outages of any control equipment or systems the 

control equipment or system will be returned to full operation as expeditiously as 

practicable.

7. Enforcement [40 CFR § 49.5513(i)]:

a. Notwithstanding any other provision in this permit, any credible evidence 

or information relevant to whether a source would have been in 

compliance with applicable requirements if the appropriate 

performance or compliance test had been performed can be used to 

establish whether or not a person has violated or is in violation of any 

applicable standard.

b. During periods of start-up and shutdown the otherwise applicable 

emission limits or requirements for opacity and particulate matter shall not 

apply provided that:

(i) At all times the facility is operated in a manner consistent with 

good practice for minimizing emissions, and the permittee uses best 

efforts regarding planning, design, and operating procedures 

to meet the otherwise applicable emission limit;

(ii) The frequency and duration of operation in start-up or shutdown 

mode are minimized to the maximum extent practicable; and

(iii) The permittee's actions during start-up and shutdown periods 

are documented by properly signed, contemporaneous

operating logs, or other relevant evidence.

c. Emissions in excess of the level of the applicable emission limit or

requirement that occur due to a malfunction shall constitute a violation of 

the applicable emission limit. However, it shall be an affirmative 

defense in an enforcement action seeking penalties if the permittee has 

met with all of the following conditions:
Page 14 of 62

(i) The malfunction was the result of a sudden and unavoidable 

failure of process or air pollution control equipment and did not 

result from inadequate design or construction of the process 

or air pollution control equipment;

(ii) The malfunction did not result from operator error or neglect, or

from improper operation or maintenance procedures;

(iii) The excess emissions were not part of a recurring pattern

indicative of inadequate design, operation, or maintenance;

(iv) Steps were immediately taken to correct conditions leading to the

malfunction, and the amount and duration of the excess emissions 

caused by the malfunction were minimized to the maximum extent 

practicable;

(v) All possible steps were taken to minimize the impact of the 

excess emissions on ambient air quality;

(vi) All emissions monitoring systems were kept in operation if at 

all possible; and

(vii) The permittee's actions in response to the excess emissions were 

documented by properly signed, contemporaneous operating logs, 

or other relevant evidence.

8. Regional Haze Best Available Retrofit Technology (BART) 

Requirements [40 CFR § 49.5513(j)]:

a. Total cumulative NOX emissions from boilers U1, U2, and U3, from 

January 1, 2009 to December 31, 2044, may not exceed the 2009-2044 

NOX Cap (494,899 tons). The permittee must implement the applicable 

operating scenario under 40 CFR § 49.5513(j)(3)(i) to ensure NOX

emission reductions sufficient to maintain total cumulative NOX

emissions from U1 through U3 below the 2009-2044 NOX Cap. [40 

CFR § 49.5513(j)(3)]

b. No later than December 1, 2019, the permittee must notify U.S. EPA of 

the applicable Alternative for ensuring compliance with the 2009-2044 

NOx Cap. [40 CFR § 49.5513(j)(4)(i)]

c. Beginning in 2015, and annually thereafter until the earlier of December 

22, 2044 or the date on which the permittee ceases conventional coalfired electricity generation by all coal-fired Units at NGS, the permittee 

must report to U.S. EPA the annual heat input and the annual emissions 
Page 15 of 62

of sulfur dioxide, carbon dioxide, and NOX from the previous full 

calendar year. In addition, the permittee must also report total cumulative 

emissions of NOX from NGS to assure compliance with the 2009-2044 

NOX Cap and the 2009-2029 NOX Cap (416,865 tons), if applicable. The 

permittee must make this report available to the public, either through a 

link on its website or directly on its website. The report must be made 

available within 30 days of the submittal deadline associated with the 

annual emission inventory required by this permit. [40 CFR § 

49.5513(j)(4)(ii)]

d. No later than December 31, 2020, the permittee must submit an 

application to revise its existing Part 71 Operating Permit to incorporate 

the requirements and emission limits of the applicable Alternative to 

BART under 40 CFR § 49.5513(j)(3) and the NOx emission limits 

specified in § 49.5513(j)(4)(iii) . The Part 71 operating permit for NGS 

must incorporate practically enforceable limits for NOX of 0.24 

lb/MMBtu, on a 30-day rolling average basis, for each unit equipped with 

LNB/SOFA, and 0.07 lb/MMBtu, on a rolling average basis of 30 boiler 

operating days, for each unit equipped with SCR, as federally enforceable 

permit conditions. [40 CFR § 49.5513(j)(4)(iii)]

e. If Alternative B operating scenario, as defined in 40 CFR § 

49.5513(j)(3)(i)(D), is selected, the permittee shall submit annual 

Emission Reduction Plans to the EPA as specified in 40 CFR § 

49.5513(j)(4)(iv)(A-C). [40 CFR § 49.5513(j)(4)(iv)]

f. The permittee shall comply with the following requirements for NOX

CEMS [40 CFR § 49.5513(j)(5)]:

(i) At all times, the permittee must maintain, calibrate, and operate a 

CEMS, in full compliance with the requirements found at 40 CFR 

part 75, to accurately measure NOX, diluent, and stack gas 

volumetric flow rate from each unit. All hourly valid data will be 

used to determine compliance with the emission limitations for 

NOX in Condition II.A.8.a for each unit. If the CEMs data is not 

valid, that CEMs data shall be treated as missing data and not used 

to calculate the emission average. CEMs data does not need to be 

bias adjusted as defined in 40 CFR part 75. Each required CEMS 

must obtain valid data for at least 90 percent of the unit operating 

hours, on an annual basis.

(ii) The permittee shall comply with the quality assurance procedures 

for CEMS found in 40 CFR part 75. In addition to these Part 75 

requirements, relative accuracy test audits shall be calculated for 

both the NOX pounds per hour measurement and the heat input 

measurement. The calculation of NOX pounds per hour and heat 
Page 16 of 62

input relative accuracy shall be evaluated each time the CEMS 

undergo relative accuracy testing. 

g. The permittee shall maintain the following recordsfor each of the coalfired units until the earlier of December 22, 2044 or the date that 

conventional coal-fired operation of all units at NGS permanently ceases:

[40 CFR § 49.5513(j)(7)]

(i) Records of all CEMS data, including the date, place, and time of 

sampling or measurement; parameters sampled or measured; 

and results as required by 40 CFR Part 75 and as necessary to 

calculate each unit’s pounds of NOX and heat input for each 

hour.

(ii) Records of quality assurance and quality control activities for 

emissions measuring systems including, but not limited to, any 

records required by 40 CFR part 75.

(iii) Any other records required by 40 CFR part 75.

h. The permittee must notify EPA within two weeks after completion of 

installation of NOX control technology on boiler U1, U2, or U3. [40 CFR § 

49.5513(j)(8)(i)]

i. At all times, including periods of startup, shutdown, and malfunction, the 

permittee shall, to the extent practicable, maintain and operate boilers U1-

U3, including associated air pollution control equipment, in a manner 

consistent with good air pollution control practices for minimizing 

emissions. [40 CFR § 49.5513(j)(10)]

II.B. PSD Permit Requirements [PSD Permits AZ 08-01 and AZ 08-01A]

Pursuant to the PSD Permits #AZ 08-01 issued on November 20, 2008 and #AZ 08-01A 

issued on February 8, 2012, the permittee shall comply with the following:

1. Emission Limits: The permittee shall comply with the following emission limits 

for each of the boilers U1 through U3: [PSD Permit AZ 08-01A, Condition 

IX.B]

a. CO emissions shall not exceed the following (BACT requirements):

(i) 0.23 lb/MMBtu based on a 30-day rolling average, and

(ii) 0.15 lb/MMBtu based on a 12-month rolling average.

b. NOx emissions shall not exceed 0.24 lb/MMBtu based on a 30-day rolling 

average.
Page 17 of 62

2. At all times, including periods of startup and shutdown, the permittee shall, to the

extent practicable, maintain and operate the LNB/SOFA system in a manner

consistent with good combustion practices to minimize emissions. [PSD Permit 

AZ 08-01A, Condition IX.D]

3. Continuous Emission Monitoring Systems Requirements: [PSD Permit AZ 

08-01A, Condition IX.E]

a. Within 60 days of completion of installation of each LNB/SOFA system, 

the permittee shall install, and thereafter operate, maintain: certify, and 

quality assure a continuous emission monitoring system (CEMS) for each 

boiler which measures stack gas CO concentrations in lb/MMBtu.

b. The CO CEMS shall meet the applicable requirements of 40 CFR Part 60 

Appendix B, Performance Specifications 3 and 4A, and 40 CFR Part 60 

Appendix F, Procedure 1. The diluent monitor (O2 or CO2) must meet the 

requirements of 40 CFR Part 75. 

c. The permittee shall operate, maintain, and quality-assure according to the 

requirements of 40 CFR Part 75 a CEMS for each boiler which measures 

stack gas NOx concentrations in lb/MMBtu. The NOx CEMs must meet 

the requirements of 40 CFR Part 75.

d. The CO CEMS shall complete a minimum of one cycle of operations 

(sampling, analyzing and data recording) for each successive 15-minute 

period.

e. The CO CEMS shall be tested annually and quarterly in accordance with 

the requirements of 40 CFR 60 Appendix F, Procedure 1. The NOx CEMS 

shall meet the quality assurance requirement found in 40 CFR Part 75.

4. Recordkeeping and Reporting Requirements [PSD Permit AZ 08-01A, 

Condition IX.G]

a. The permittee shall maintain records of the hours of operation for U1, U2 

and U3 on a monthly basis.

b. The permittee shall maintain records of the amount of fuel used in U1, U2 

and U3 on a monthly basis.

c. The permittee shall maintain all records on site of actual operating data 

and emissions calculations for emissions limits required in Condition 

II.B.1.

d. The permittee shall maintain CEMS records that contain the following: the 

occurrence and duration of any startup, shutdown or malfunction, 
Page 18 of 62

performance testing, evaluations, calibrations, checks, adjustments, 

maintenance, duration of any periods during which a continuous 

monitoring system or monitoring device is inoperative, and emission 

measurements.

e. The permittee shall maintain records and submit a written report of all 

excess emissions to EPA semi-annually. The report is due on the 30th day 

following the end of the calendar quarter and shall include the following:

(i) Time intervals, data and magnitude of the excess emissions, the 

nature and cause (if known), corrective actions taken and 

preventive measures adopted;

(ii) Applicable time and date of each period during which the CEMS 

was inoperative (monitor down time), except for zero and span 

checks, and the nature of system repairs or adjustments; and

(iii) A negative declaration when no excess emissions occurred or 

when the CEMS has not been inoperative, repaired, or adjusted.

f. Excess emissions shall be defined as any operating day in which the 30-

day rolling average CO and NOx concentration, as measured by the 

CEMS, exceeds the maximum emission limits set forth in Condition 

II.B.1.

g. A period of monitor down time shall be any unit operating hour in which

sufficient data are not obtained to validate the hour for CO, NOx, or O2.

h. Excess emissions indicated by the CEMS shall be considered violations of

the applicable emission limit.

II.C. Acid Rain Requirements [40 CFR Parts 72-78; Phase II Acid Rain Permit]

The permittee shall comply with the requirements listed in the attached acid rain permit 

renewal (see Attachment B).

II.D. Visibility Federal Implementation Plan Requirements [40 CFR § 52.145(d)]

1. Definitions. The following definitions apply to Condition II.D of this permit [40 

CFR § 52.145(d)(1)]:

a. “Administrator” means the Administrator of EPA or his/her designee. 

b. “Affected Units” means steam-generating units U1, U2 and U3 at the 

Navajo Generating Station, all of which are subject to the emission 

limitation in Condition II.D.2 of this permit.
Page 19 of 62

c. “Boiler Operating Day” for each of the boiler units at the Navajo 

Generating Station is defined as a 24-hour calendar day (the period of time 

between 12:01 a.m. and 12:00 midnight in Page, Arizona) during which 

coal is combusted in that unit for the entire 24 hours.

d. “Unit-Week of Maintenance” means a period of 7 days during which a 

fossil fuel-fired steam-generating unit is under repair and no coal is 

combusted in the unit.

2. Emission limitation. The permittee shall not discharge or cause the discharge of 

sulfur oxides into the atmosphere in excess of 42 ng/J [0.10 pound per million 

British thermal units (lb/MMBtu)] heat input [40 CFR § 52.145(d)(2)].

3. Compliance determination. Compliance with the emission limit in Condition 

II.D.2 of this permit shall be determined daily on a plant-wide rolling annual basis 

as follows [40 CFR § 52.145(d)(3)]:

a. For each boiler operating day at each steam generating unit subject to the 

emission limitation in Condition II.D.2 of this permit, the permittee shall 

record the unit’s hourly SO2 emissions using the data from the continuous 

emission monitoring systems, required in Condition II.D.4 of this permit,

and the daily electric energy generated by the unit (in megawatt-hours) as 

measured by the megawatt-hour meter for the unit.

b. Compute the average daily SO2 emission rate in ng/J (lb/MMBtu) 

following the procedures set out in Method 19, Appendix A, 40 CFR Part 

60 in effect on October 3, 1991.

c. For each boiler operating day for each affected unit, calculate the product 

of the daily SO2 emission rate (computed according to Condition II.D.3.b 

of this permit) and the daily electric energy generated (recorded according 

to Condition II.D.3.a of this permit) for each unit.

d. For each affected unit, identify the previous 365 boiler operating days to 

be used in the compliance determination. Except as provided in Condition

II.D.7 of this permit, all of the immediately preceding 365 boiler operating 

days will be used for compliance determinations.

e. Sum, for all affected units, the products of the daily SO2 emission rateelectric energy generated (as calculated according to Condition II.D.3.c of 

this permit) for the boiler operating days identified in Condition II.D.3d of 

this permit.
Page 20 of 62

f. Sum, for all affected units, the daily electric energy generated (recorded 

according to Condition II.D.3.a of this permit) for the boiler operating 

days identified in Condition II.D.3.d of this permit.

g. Calculate the weighted plant-wide annual average SO2 emission rate by 

dividing the sum of the products determined according to Condition 

II.D.3.e of this permit by the sum of the electric energy generated 

determined according to Condition II.D.3.f of this permit.

h. The weighted plant-wide annual average SO2 emission rate shall be used 

to determine compliance with the emission limitation in Condition II.D.2 

of this permit.

4. Continuous emission monitoring. The permittee shall install, maintain, and 

operate continuous emission monitoring systems to determine compliance with 

the emission limitation in Condition II.D.2 of this permit as calculated in 

Condition II.D.3 of this permit. This equipment shall meet the specifications in 

Appendix B of 40 CFR Part 60 in effect on October 3, 1991. The permittee shall 

comply with the quality assurance procedures for continuous emission monitoring 

systems found in Appendix F of 40 CFR 60 in effect on October 3, 1991 [40 CFR 

§ 52.145(d)(4)].

5. Reporting requirements. For each steam generating unit subject to the emission 

limitation in Condition II.D.2 of this permit, the permittee [40 CFR §

52.145(d)(5)]:

a. Shall furnish the Administrator written notification, on a quarterly basis, 

on emissions of SO2, and either oxygen or carbon dioxide, according to 

the procedures found in 40 CFR § 60.7 in effect on October 3, 1991.

b. Shall furnish the Administrator written notification of the daily electric 

energy generated in megawatt-hours.

c. Shall maintain records according to the procedures in 40 CFR § 60.7 in 

effect on October 3, 1991.

d. Shall notify the Administrator by telephone, in writing, or by electronic 

mail sent to AEO_R9@epa.gov within one business day of any outage of 

the control system needed for compliance with the emission limitation in 

Condition II.D.2 of this permit and shall submit a follow-up written report 

within 30 days of the repairs stating how the repairs were accomplished 

and justifying the amount of time taken for the repairs.

6. Compliance dates. The requirements of Section II.D of this permit shall be 

applicable to all units at this facility beginning on August 19, 1999 [40 CFR §

52.145(d)(6)].
Page 21 of 62

7. Exclusion for catastrophic failure. Any periods of emissions from an affected unit 

for which the Administrator finds that the control equipment or system for such 

unit is out of service because of catastrophic failure of the control system which 

occurred for reasons beyond the control of the permittee and could not have been 

prevented by good engineering practices will be excluded from the compliance 

determination. Events which are the consequence of lack of appropriate 

maintenance or of intentional or negligent conduct or omissions of the permittee

or the control system design, construction, or operating contractors do not 

constitute catastrophic failure [40 CFR § 52.145(d)(10)].

8. Equipment operation. The permittee shall optimally operate all equipment or 

systems needed to comply with the requirements of this paragraph consistent with 

good engineering practices to keep emissions at or below the emission limitation 

in Condition II.D.2 of this permit, and following outages of any control 

equipment or system the control equipment or system will be returned to full 

operation as expeditiously as practicable [40 CFR § 52.145(d)(11)].

9. Maintenance scheduling. On March 16 of each year starting in 1993, the permittee

shall prepare and submit to the Administrator a long-term maintenance plan for 

the Navajo Generating Station which accommodates the maintenance 

requirements for the other generating facilities on the Navajo Generating Station 

grid covering the period from March 16 to March 15 of the next year and showing 

at least 6 unit-weeks of maintenance for the Navajo Generating Station during the 

November 1 to March 15 period, except as provided in Condition II.D.10 of this 

permit. This plan shall be developed consistent with the criteria established by the 

Western Electric Coordinating Council of the North American Electric Reliability 

Corporation to ensure an adequate reserve margin of electric generating capacity. 

At the time that a plan is transmitted to the Administrator, the permittee shall 

notify the Administrator in writing if less than the full scheduled unit-weeks of 

maintenance were conducted for the period covered by the previous plan and shall 

furnish a written report stating how that year qualified for one of the exceptions 

identified in Condition II.D.10 of this permit [40 CFR § 52.145(d)(12)].

10. Exceptions for maintenance scheduling. The permittee shall conduct a full 6 unitweeks of maintenance in accordance with the plan required in Condition II.D.9 of 

this permit unless the permittee can demonstrate to the satisfaction of the 

Administrator that a full 6 unit-weeks of maintenance during the November 1 to 

March 15 period should not be required because of the following [40 CFR §

52.145(d)(13)]:

a. There is no need for 6 unit-weeks of scheduled periodic maintenance in 

the year covered by the plan;
Page 22 of 62

b. The reserve margin on any electrical system served by the Navajo 

Generating Station would fall to an inadequate level, as defined by the 

criteria referred to in Condition II.D.9 of this permit.

c. The cost of compliance with this requirement would be excessive. The 

cost of compliance would be excessive when the economic savings to the 

permittee of moving maintenance out of the November 1 to March 15 

period exceeds $50,000 per unit-day of maintenance moved.

d. A major forced outage at a unit occurs outside of the November 1 to 

March 15 period, and necessary periodic maintenance occurs during the 

period of forced outage. 

11. If the Administrator determines that a full 6 unit-weeks of maintenance during the 

November 1 to March 15 period should not be required, the permittee shall 

nevertheless conduct that amount of scheduled maintenance that is not precluded 

by the Administrator. Generally, the permittee shall make best efforts to conduct 

as much scheduled maintenance as practicable during the November 1 to March 

15 period. [40 CFR § 52.145(d)(13)]

II.E. NSPS General Provisions [40 CFR Part 60, Subpart A]

The following requirements apply to the affected facilities in the limestone handling 

system in accordance with 40 CFR Part 60, Subparts A and OOO (“Standards of 

Performance for Nonmetallic Mineral Processing Plants”) and to the emergency fire 

pump (NGS-120A) in accordance with 40 CFR Part 60, Subparts A and IIII (“Standards 

of Performance for Stationary Compression Ignition Internal Combustion Engines”):

1. All requests, reports, applications, submittals, and other communications to the 

NNEPA pursuant to 40 CFR Part 60 shall be submitted in duplicate to the EPA 

Region 9 office at the following address [40 CFR § 60.4(a)]:

Director, Air Division (Attn: AIR-1)

EPA Region IX

75 Hawthorne Street

San Francisco, CA 94105

2. The permittee shall maintain records of the occurrence and duration of any 

startup, shutdown, or malfunction in the operation of an affected facility; any 

malfunction of the air pollution control equipment; or any periods during which a 

continuous monitoring system or monitoring device is inoperative [40 CFR §

60.7(b)].

3. The availability to the public of information provided to, or otherwise obtained 

by, the EPA Administrator under this permit shall be governed by 40 CFR § 2.

(Information submitted voluntarily to the Administrator for the purposes of 
Page 23 of 62

compliance with 40 CFR §§ 60.5 and 60.6 is governed by 40 CFR §§ 2.201 

through § 2.213 and not by 40 CFR § 2.301.) [40 CFR § 60.9].

6. The opacity standards set forth in 40 CFR Part 60 shall apply at all times except 

during periods of startup, shutdown, malfunction, and as otherwise provided [40 

CFR § 60.11(c)].

7. At all times, including periods of startup, shutdown, and malfunction, the 

permittee shall, to the extent practicable, maintain and operate the affected 

facilities, including associated air pollution control equipment, in a manner 

consistent with good air pollution control practice for minimizing emissions. 

Determination of whether acceptable operating and maintenance procedures are 

being used will be based on information available to the Administrator which may 

include, but is not limited to, monitoring results, opacity observations, review of 

operating and maintenance procedures, and inspection of the source [40 CFR §

60.11(d)].

8. For the purpose of submitting compliance certifications or establishing whether or 

not a person has violated or is in violation of any standard in 40 CFR Part 60, 

nothing in 40 CFR Part 60 shall preclude the use, including the exclusive use, of 

any credible evidence or information, relevant to whether a source would have 

been in compliance with applicable requirements if the appropriate performance 

or compliance test or procedure had been performed [40 CFR § 60.11(g)].

9. The permittee shall not build, erect, install, or use any article, machine, equipment 

or process, the use of which conceals an emission which would otherwise 

constitute a violation of an applicable standard. Such concealment includes, but is 

not limited to, the use of gaseous diluents to achieve compliance with an opacity 

standard or with a standard which is based on the concentration of a pollutant in 

the gases discharged to the atmosphere [40 CFR § 60.12].

10. With respect to compliance with all New Source Performance Standards (NSPS) 

of 40 CFR Part 60, the permittee shall comply with the “General notification and 

reporting requirements” found in 40 CFR § 60.19 [40 CFR § 60.19].

11. The permittee shall provide written notification to NNEPA and US EPA or, if 

acceptable to NNEPA, US EPA and the permittee, electronic notification to 

NNEPA and US EPA of any reconstruction of an affected facility, or any physical 

or operational change to an affected facility which may increase the emission rate 

of any air pollutant to which a standard applies, unless that change is specifically 

exempted under this permit or in 40 CFR § 60.14(e) [40 CFR § 60.7(a)].
Page 24 of 62

II.F. NSPS for Limestone Handling System, 40 CFR Part 60, Subpart OOO Requirements

The permittee shall comply with the following emission limitations applicable to affected 

facilities in the limestone handling system in accordance with 40 CFR Part 60, Subpart 

OOO (“Standards of Performance for Nonmetallic Mineral Processing Plants”):

1. Any transfer point on belt conveyors or any other affected facility shall not 

discharge any stack emissions which [40 CFR § 60.672(a)]:

a. Contain particulate matter in excess of 0.05 g/dscm (0.022 gr/ dscf), and

b. Exhibit greater than 7 percent opacity. 

2. Any transfer point on belt conveyors or any other affected facility shall not 

discharge any fugitive emissions which exhibit greater than 10 percent opacity

[40 CFR § 60.672(b)].

3. Any crusher at which a capture system is not used shall not discharge fugitive 

emissions which exhibit greater than 15 percent opacity [40 CFR § 60.672(c)].

4. Truck dumping of nonmetallic minerals into any screening operation, feed hopper 

or crusher is exempt from the requirements of this 40 CFR § 60.672 [40 CFR §

60.672(d)].

5. If any transfer point on a conveyor belt or any other affected facility is enclosed in 

a building, then each enclosed affected facility must comply with the emission 

limits in Conditions II.F.1, II.F.2, and II.F.3, or the building enclosing the affected 

facility or facilities must comply with the following emission limits:

a. Fugitive emissions from building openings (except for vents, as defined in 

40 CFR § 60.671) must not exceed 7 percent opacity [40 CFR §

60.672(e)(1)].

b. Vents (as defined in 40 CFR § 60.671) in the building must meet the stack 

emission limits in Condition II.F.1 [40 CFR § 60.672(e)(2)].

6. Any baghouse that controls emissions from only an individual, enclosed storage 

bin, shall not discharge stack emissions which exhibit greater than 7 percent 

opacity [40 CFR § 60.672(f)].

II.G. Monitoring and Testing Requirements to Comply with NSPS for Limestone Handling 

System, 40 CFR Part 60, Subpart OOO

Pursuant to the Reopening Permit to this Part 71 Permit issued on November 13, 2003, 

the permittee shall comply with the following [40 CFR § 71.6(a)(3)]:
Page 25 of 62

1. Once per five year permit term, and at such other times as specified by NNEPA, 

the permittee shall conduct performance tests for particulate matter emissions 

from the exhaust stacks of baghouses DC-9, DC-10, and DC-11 using EPA 

Method 5 or Method 17, and furnish US EPA and NNEPA a written report of the 

results of such test. The tests shall be conducted at the maximum operating 

capacity of the facility being tested. Upon written request from the permittee, 

NNEPA may approve the conducting of performance tests at a lower specified 

production rate. In addition to testing once per five year permit term, if during any 

12 consecutive month period visible emissions are observed three times from any 

one baghouse, the permittee shall conduct a performance test on that baghouse 

within 120 days of the third observation. All observations of visible emissions by 

the permittee, US EPA, or NNEPA shall count toward the 12 month total.

2. The permittee shall conduct a weekly visual emission survey of the exhaust stacks 

of baghouses DC-9, DC-10, and DC-11. The weekly survey shall be conducted 

while the equipment is operating, and during daylight hours, by a person certified 

in EPA Method 9 (Visual Determination of the Opacity of Emissions from 

Stationary Sources). If any visible emissions are observed, the permittee shall 

conduct an opacity test using EPA Method 9 within 24 hours while the equipment 

is operating in accordance with 40 CFR § 60.675.

3. For each visible emission observation or Method 9 opacity test, the permittee

shall record and maintain the following records:

a. the date and time of the observation and the name of the observer.

b. the unit ID number.

c. a statement of whether visible emissions were detected, and if so, whether 

they were observed continuously or intermittently.

a. the results of the Method 9 test, if required.

II.H. NSPS for Stationary Compression Ignition Internal Combustion Engines, 40 CFR 

Part 60, Subpart IIII Requirements 

The following requirements apply to the emergency fire pump (NGS-120A) in 

accordance with 40 CFR Part 60, Subpart IIII (“Standards of Performance for Stationary 

Compression Ignition Internal Combustion Engines”):

1. Emissions from engine NGS-120A shall not exceed the following [40 CFR §

60.4205(c)]:

a. 4.0 g/KW-hr or 3.0 g/HP-hr for NMHC and NOX emissions.

b. 0.2 g/KW-hr or 0.15 g/HP-hr for PM emissions.
Page 26 of 62

2. The permittee shall use diesel fuel for the emergency fire pump with the 

following per-gallon standards, except that any existing diesel fuel purchased (or 

otherwise obtained) prior to October 1, 2010, may be used until depleted: [40 

CFR § 60.4207(b)]

a. 15 ppm sulfur content; and

b. Cetane index or aromatic content, as follows:

(i) A minimum cetane index of 40; or

(ii) A maximum aromatic content of 35 volume percent. 

3. The permittee shall comply with the following operating requirements [40 CFR §

60.4211(a)]:

a. Operate and maintain the emergency fire pump (NGS-120A) according to 

the manufacturer's emission-related written instructions;

b. Change only those emission-related settings that are permitted by the 

manufacturer; and

c. Meet the requirements of 40 CFR Parts 89, 94 and/or 1068, as applicable.

4. The fire pump must be certified to the emission standards in Condition II.H.1 for 

the same model year and NFPA nameplate engine power. The engine must be 

installed and configured according to the manufacturer's emission-related 

specifications. [40 CFR § 60.4211(c)]

5. The operation hours for the emergency fire pump (NGS-120A) shall be limited to 

the following [40 CFR § 60.4211(f)]:

a. No use time limit for emergency situations.

b. A maximum of 100 hours per calendar year for maintenance/testing and 

emergency demand response, as specified below, and for non-emergency 

situations: 

(i) Maintenance checks and readiness testing, provided that the tests 

are recommended by federal, state or local government, the 

manufacturer, the vendor, the regional transmission organization or 

equivalent balancing authority and transmission operator, or the 

insurance company associated with the engine. 
Page 27 of 62

(ii) Emergency demand response for periods in which the Reliability 

Coordinator under the North American Electric Reliability 

Corporation (NERC) Reliability Standard EOP-002-3, Capacity 

and Energy Emergencies (incorporated by reference into 40 CFR §

63.14), or other authorized entity as determined by the Reliability 

Coordinator, has declared an Energy Emergency Alert Level 2 as 

defined in the NERC Reliability Standard EOP-002-3.

(iii) For periods where there is a deviation of voltage or frequency of 5 

percent or greater below standard voltage or frequency.

c. A maximum of 50 hours per calendar year in non-emergency situations. 

The 50 hours per year for non-emergency situations cannot be used for 

peak shaving or non-emergency demand response, or to generate income 

for a facility to supply power to an electric grid or otherwise supply power 

as part of a financial arrangement with another entity.

II.I. NESHAP General Provisions [40 CFR Part 63, Subpart A]

1. Prohibited Activities and Circumvention [40 CFR § 63.4]

a. The permittee shall not operate any affected source in violation of the

requirements of 40 CFR Part 63. Affected sources subject to and in 

compliance with either an extension of compliance or an exemption from 

compliance are not in violation of the requirements of 40 CFR Part 63. An 

extension of compliance can be granted by the Administrator under this 

part.

b. The permittee shall not fail to keep records, notify, report, or revise reports

as required by 40 CFR Part 63.

c. The permittee shall not build, erect, install, or use any article, machine,

equipment, or process to conceal an emission that would otherwise 

constitute noncompliance with a relevant standard. Such concealment 

includes, but is not limited to:

(i) The use of diluents to achieve compliance with a relevant standard

based on the concentration of a pollutant in the effluent discharged 

to the atmosphere; or

(ii) The use of gaseous diluents to achieve compliance with a relevant

standard for visible emissions.

2. The permittee shall follow the preconstruction review and notification

requirements specified in 40 CFR § 63.5.
Page 28 of 62

3. The permittee shall follow requirements for compliance with emission standards 

and operation and maintenance requirements specified in 40 CFR § 63.6(b).

4. Monitoring shall be conducted as set forth in 40 CFR § 63.8 and the relevant

standard.

5. The permittee shall follow the notification requirements specified in 40 CFR §

63.9.

6. The permittee shall maintain files of all information (including all reports and

notifications) required by 40 CFR Part 63 recorded in a form suitable and readily

available for expeditious inspection and review. The files shall be retained for at 

least 5 years following the date of each occurrence, measurement, maintenance, 

corrective action, report, or record. At a minimum, the most recent 2 years of data 

shall be retained on site. The remaining 3 years of data may be retained off site. 

Such files may be maintained on microfilm, on a computer, on computer floppy 

disks, on magnetic tape disks, on microfiche, or on other forms of electronic 

storage. [40 CFR § 63.10(b)(1)]

II.J. NESHAP for Coal- and Oil-Fired Electric Utility Steam Generating Units, 40 CFR 

Part 63, Subpart UUUUU Requirements

Boilers U1, U2, and U3 are subject to 40 CFR Part 63, Subpart UUUUU (“National 

Emission Standards for Hazardous Air Pollutants: Coal- and Oil-Fired Electric Utility 

Steam Generating Units”) and shall comply with the following requirements:

1. The permittee shall comply with the following schedule [Extension Approval 

Letter Dated January 27, 2014]:

a. By October 1, 2015, commence construction to incorporate the mercury 

control strategy on-site. [Note: The permittee plans to install a calcium 

bromide application and powder activated carbon (PAC) injection system 

to control the Hg emissions.]

b. By April 16, 2016, complete on-site construction and comply with all 

mercury provisions of this NESHAP. 

2. The permittee shall submit progress reports to both NNEPA and U.S. EPA that 

indicate the status of completion of each step of the compliance schedule listed in 

Condition II.J.1 within 30 days after the completion date for that step [Extension 

Approval Letter Dated January 27, 2014].

3. The permittee shall submit a final report to both NNEPA and U.S. EPA within 30 

days after the final compliance deadline describing the chosen control technology 

and demonstrating that it is meeting the requirements under this NESHAP

[Extension Approval Letter Dated January 27, 2014].
Page 29 of 62

4. The permittee shall comply with the following emission limits at all times except 

during periods of startup and shutdown [40 CFR §§ 63.9991(a)(1) and 

63.10000(a)]:

a. By April 16, 2015, filterable PM emissions shall not exceed 0.03 

lb/MMBtu or 0.3 lb/MWh.

b. By April 16, 2015, SO2 emissions shall not exceed 0.2 lb/MMBtu or 1.5 

lb/MWh.

c. By April 16, 2016, mercury (Hg) emissions shall not exceed 1.2 lb/TBtu 

or 0.013 lb/GWh. 

5. After April 16, 2015, the permitttee shall comply with the following work practice 

standards: [40 CFR § 63.9991(a)(1)]

a. Conduct a tune-up of the EGU burners and combustion controls at least 

each 48 calendar months if neural network combustion optimization 

software is employed, as specified in 40 CFR § 63.10021(e).

b. Comply with the applicable requirements for startup and shutdown periods 

as specified in Table 3 of 40 CFR Part 63, Subpart UUUUU. [See 

Attachment C for details]

6. The permittee has elected to demonstrate compliance with the emissions limits in 

Condition II.J.4 using the following methods:

a. PM: Conducting quarterly stack testing until PM CEMS are operating 

properly. PM CEMS have been installed and are expected to be in full 

operation in late 2015. 

b. SO2: Operation of the existing SO2 CEMS.

c. Hg: Use of sorbent trap monitoring system for each stack.

7. The permittee shall comply with the applicable compliance, monitoring, testing, 

notification, recordkeeping, and reporting requirements under 40 CFR Part 63, 

Subpart UUUUU, specified in Attachment C of this permit by. The requirements 

pertaining to Hg emissions are not applicable until April 16, 2016. 

II.K. NESHAP for Industrial, Commercial, and Institutional Boilers and Process Heaters, 

40 CFR Part 63, Subpart DDDDD Requirements

The following requirements apply to the auxiliary boilers (AUX A and AUX B) in 

accordance with 40 CFR Part 63, Subpart DDDDD (“National Emission Standards for 
Page 30 of 62

Hazardous Air Pollutants for Major Sources: Industrial, Commercial, and Institutional 

Boilers and Process Heaters”):

1. The permittee shall comply with the applicable requirements specified under 40 

CFR Part 63, Subpart DDDDD by January 31, 2016 [40 CFR § 63.7495(b)].

2. The permittee shall not operate either of the auxiliary boilers (AUX A and AUX 

B) for more than 10% of the annual capacity, in order to quality for “limited-use” 

units [40 CFR §§ 71.6(a)(1) and 63.7575(d)(3)].

3. The permittee shall complete a tune-up as specified below for each of the

auxiliary boilers every 5 years [40 CFR § 63.7500(c) and 63.7540(a)(10)].

a. As applicable, inspect the burner and clean or replace any components of 

the burner as necessary (the permittee may delay the burner inspection 

until the next scheduled unit shutdown). Units that produce electricity for 

sale may delay the burner inspection until the first outage, not to exceed 

36 months from the previous inspection. At units where entry into a piece 

of process equipment or into a storage vessel is required to complete the 

tune-up inspections, inspections are required only during planned entries 

into the storage vessel or process equipment;

b. Inspect the flame pattern, as applicable, and adjust the burner as necessary 

to optimize the flame pattern. The adjustment should be consistent with 

the manufacturer's specifications, if available;

c. Inspect the system controlling the air-to-fuel ratio, as applicable, and 

ensure that it is correctly calibrated and functioning properly (the 

permittee may delay the inspection until the next scheduled unit 

shutdown). Units that produce electricity for sale may delay the inspection 

until the first outage, not to exceed 36 months from the previous 

inspection;

d. Optimize total emissions of CO. This optimization should be consistent 

with the manufacturer's specifications, if available, and with any NOX

requirement to which the unit is subject;

e. Measure the concentrations in the effluent stream of CO in parts per 

million, by volume, and oxygen in volume percent, before and after the 

adjustments are made (measurements may be either on a dry or wet basis, 

as long as it is the same basis before and after the adjustments are made). 

Measurements may be taken using a portable CO analyzer; and

f. Maintain on-site and submit, if requested by the Administrator, an annual 

report containing the information specified below:
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(i) The concentrations of CO in the effluent stream in parts per 

million by volume, and oxygen in volume percent, measured at 

high fire or typical operating load, before and after the tune-up of 

the boiler or process heater; and

(ii) A description of any corrective actions taken as a part of the tuneup.

4. The permittee shall complete an initial tune-up for the affected boilers (AUX A 

and AUX B) no later than January 31, 2016. If the affected boilers have not 

operated between March 21, 2011 and January 31, 2016, the permittee shall

complete an initial tune-up no later than 30 days after the re-start of the affected 

boilers [40 CFR § 63.7510(e) and (j)].

5. The permittee shall keep the following records:

(a) A copy of each notification and report submitted to comply with 40 CFR 

Part 63, Subpart DDDDD, including all documentation supporting any 

Initial Notification or Notification of Compliance Status or semiannual 

compliance report, according to the requirements in 40 CFR §

63.10(b)(2)(xiv) [40 CFR § 63.7555(a)(1)].

(b) Records of compliance demonstrations as required in 40 CFR §

63.10(b)(2)(viii) [40 CFR § 63.7555(a)(2)].

(c) Fuel use records for the days the boiler was operating, in order to 

demonstrate compliance with Condition II.K.2 [40 CFR § 63.7525(k)].

(d) Records of the calendar date, time, occurrence, and duration of each 

startup and shutdown [40 CFR § 63.7555(i)].

(e) Records of the amount of fuels used during each startup and shutdown [40 

CFR § 63.7555(j)].

6. The permittee shall submit a compliance report every 5 years. The first 

compliance report shall cover the time period of January 31, 2016 to January 31, 

2021 and shall be postmarked or submitted no later than July 31, 2021. The report 

shall include the following: [40 CFR § 63.7550]

(a) Company and Facility name and address;

(b) Process unit information, emissions limitations, and operating parameter 

limitations;

(c) Date of report and beginning and ending dates of the reporting period;
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(d) The total operating time during the reporting period;

(e) The date of the most recent tune-up for each unit; and the date of the most 

recent burner inspection if it was delayed until the next scheduled or 

unscheduled unit shutdown.

II.L. NESHAP for Stationary Reciprocating Internal Combustion Engines, 40 CFR Part 

63, Subpart ZZZZ Requirements

The following requirements apply to the diesel-fired emergency generators EG2, EG3, 

NPG-746, and the emergency fire pump NGS-120A in accordance with 40 CFR Part 63, 

Subpart ZZZZ (“National Emissions Standards for Hazardous Air Pollutants for 

Stationary Reciprocating Internal Combustion Engines”):

1. For emergency fire pump NGS-120A, compliance with the requirements of NSPS

for Stationary Compression Ignition Internal Combustion Engines, 40 CFR Part 

60, Subpart IIII, specified in Condition II.H, fulfills the requirements of this 

NESHAP [40 CFR § 63.6590(c)].

2. The permittee shall comply with the following work practice requirements for 

engines EG2, EG3, and NPG-746 [40 CFR § 63.6602]:

a. Change oil/filter every 500 hours of operation or annually, whichever 

comes first;

b. Inspect air cleaner every 1,000 hours of operation or annually, whichever 

comes first, and replace as necessary;

c. Inspect hoses/belts every 500 hours of operation or annually, whichever 

comes first, and replace as necessary; and

d. Minimize the engine's time spent at idle and minimize the engine's startup 

time at startup to a period needed for appropriate and safe loading of the 

engine, not to exceed 30 minutes, after which time the non-startup 

emission limitations apply.

3. For the emergency generators EG2 and NPG-746, the permittee shall use ultra 

low sulfur diesel fuel (sulfur content = 15 ppmv) after January 1, 2015, except 

that any existing diesel fuel purchased (or otherwise obtained) prior to January 1, 

2015, may be used until depleted [40 CFR § 63.6604(b)].

4. The permittee shall install a non-resettable hour meter for each of emergency 

generators EG2, EG3, and NPG-746 [40 CFR § 63.6625(f)].

5. The operation hours for each of the emergency generators EG2, EG3, and NPG746 shall be limited to the following [40 CFR § 63.6640(f)]:
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a. No use time limit for emergency situations.

b. A maximum of 100 hours per calendar year for maintenance/testing and 

emergency demand response, as specified below, and for non-emergency 

situations specified in Condition II.L.4.c: 

(i) Maintenance checks and readiness testing, provided that the tests 

are recommended by federal, state or local government, the 

manufacturer, the vendor, the regional transmission organization or 

equivalent balancing authority and transmission operator, or the

insurance company associated with the engine. 

(ii) Emergency demand response for periods in which the Reliability 

Coordinator under the North American Electric Reliability 

Corporation (NERC) Reliability Standard EOP-002-3, Capacity 

and Energy Emergencies (incorporated by reference into 40 CFR §

63.14), or other authorized entity as determined by the Reliability 

Coordinator, has declared an Energy Emergency Alert Level 2 as 

defined in the NERC Reliability Standard EOP-002-3.

(iii) For periods where there is a deviation of voltage or frequency of 5 

percent or greater below standard voltage or frequency.

c. A maximum of 50 hours per calendar year in non-emergency situations. 

The 50 hours per year for non-emergency situations cannot be used for 

peak shaving or non-emergency demand response, or to generate income 

for a facility to supply power to an electric grid or otherwise supply power 

as part of a financial arrangement with another entity.

6. The permittee shall keep the following records for the emergency generators EG2, 

EG3, and NPG-746 [40 CFR § 63.6655]:

a. Records of the maintenance conducted on the stationary RICE [40 CFR §

63.6655(e)]. 

b. Records of the hours of operation of the engine that is recorded through 

the non-resettable hour meter. The permittee shall document how many 

hours are spent for emergency operation, including what classified the 

operation as an emergency and how many hours are spent for nonemergency operation. If the engine is used for the purposes specified in 

Condition II.L.5.b.(ii) or (iii), the permittee must keep records of the 

notification of the emergency situation and the date, start time, and end 

time of engine operation [40 CFR § 63.6655(f)].
Page 34 of 62

II.M. PM CEMS Requirements

After the PM CEMS associated with boilers U1, U2, U3 operate properly, the permittee 

shall comply with the following requirements for the PM CEMS:

1. The permittee may shall operate and maintain a PM CEMS for each of the stacks

associated with boilers U1, U2, and U3 to demonstrate compliance with the PM 

emission limit specified in Condition II.A.2.b. [40 CFR § 71.6(a)(3)]

2. The operation and maintenance of PM CEMS shall comply with the applicable 

requirements for PM CEMS specified in NESHAP, Subpart UUUUU (see 

Attachment C to this permit). [40 CFR § 71.6(a)(3)]

II.N. CAM Requirements [40 CFR Part 64]

Before the PM CEMS associated with boilers U1, U2, and U3 operate properly, the 

permittee shall comply with the following CAM requirements for each of the boilers U1, 

U2, and U3:

1. Monitoring

a. The indicator ranges are defined by the following thresholds: [40 CFR § 

64.6(c)(1)(i)]

(i) For each Electrostatic Precipitator (ESP), no more than 3 chambers 

(18 fields) shall be out of service at one time.

(ii) If less than 2 spray levels are operating in each wet limestone 

scrubber, then for the same boiler, no more than 1 chamber (6 

fields) shall be out of service in the ESP for that boiler.

(iii) For each wet limestone scrubber, the temperature shall not exceed

145°F on a 1 hour average, as measured by a J-type thermocouple.

(iv) No more than one wet limestone scrubber shall be bypassed at one 

time, and the same wet limestone scrubber shall not be bypassed 

for more than 1 hour.

b. The means or devices by which the indicators will be measured are as

follows: [40 CFR § 64.6(c)(1)(ii)]

(i) Status bits from the Automatic Voltage Controllers (AVCs) shall

be recorded on a continuous basis by the BHA WinDAC Data 

Acquisition and Control Software and supplemented with 

operating logs; these status bits indicate the number of 

chambers/fields that are operational in the ESPs.

(ii) The wet limestone scrubber spray level signal shall be recorded on
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a continuous basis by a data acquisition handling system.

(iii) A J-type thermocouple at the wet limestone scrubber exhaust shall 

measure the temperature of the exhaust and be recorded as an 

hourly average by a data acquisition system.

(iv) An on/off signal on the wet limestone scrubber indicating that the

wet limestone scrubber is operational shall be recorded on a 

continuous basis by a data acquisition handling system.

b. The permittee shall conduct performance testing in accordance with 40 

CFR § 64.4(d) to ensure that compliance with the particulate matter 

emission limits in Condition II.A.2.b can be achieved when more than 3 

chambers of an ESP unit are out of service. The testing shall be conducted 

at the first possible opportunity, i.e. the earliest time during which more 

than 3 chambers are out of service in an ESP unit. [40 CFR § 

64.6(c)(1)(iii)]

2. Excursions during normal operation of the boilers are defined below [40 CFR § 

64.6(c)(2)]. Normal operation of the boiler is specified as any time the boiler is 

operating in its usual manner in accordance with good air pollution control 

practices for minimizing emissions. 

a. When an ESP unit is operating with more than 3 chambers (18 fields) out

of service.

b. When an ESP unit is operating with more than 1 chamber (6 fields) out of

service and less than 2 spray levels are operating in the wet limestone 

scrubber associated with the same boiler. 

c. When the exhaust temperature for a wet limestone scrubber exceeds 145°F 

for more than one unit on a 1 hour average basis.

d. When a wet limestone scrubber is bypassed for more than one unit and the 

same wet limestone scrubber is bypassed for more than 1 hour.

3. The permittee shall continuously monitor and log the following measurements: 

[40 CFR § 64.6(c)(3), 40 CFR § 64.7(a)]:

a. The number of chambers/fields in service for each ESP unit.

b. The number of wet limestone scrubber spray levels in service for each 

boiler unit.

c. The wet limestone scrubber exhaust temperatures at the absorber outlets of 
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each boiler unit.

d. The wet limestone scrubber on/off signal of each boiler unit.

4. At all times, the permittee shall maintain the monitoring equipment, including but

not limited to, maintaining necessary parts for routine repairs of the monitoring 

equipment. [40 CFR § 64.7(b)]

5. Except for, as applicable, monitoring malfunctions, associated repairs, and 

required quality assurance or control activities (including, as applicable, 

calibration checks and required zero and span adjustments), the permittee shall

conduct all monitoring in continuous operation (or shall collect data at all required 

intervals) at all times that the pollutant-specific emissions unit is operating. Data 

recorded during monitoring malfunctions, associated repairs, and required quality 

assurance or control activities shall not be used for purposes of this permit, 

including data averages and calculations, or fulfilling a minimum data availability 

requirement, if applicable. The permittee shall use all the data collected during all 

other periods in assessing the operation of the control device and associated 

control system. A monitoring malfunction is any sudden, infrequent, not 

reasonably preventable failure of the monitoring to provide valid data. Monitoring 

failures that are caused in part by poor maintenance or careless operation are not 

malfunctions. [40 CFR § 64.7(c)]

6. Response to excursions or exceedances [40 CFR § 64.7(d)]

a. Upon detecting an excursion or exceedance, the permittee shall restore

operation of the pollutant-specific emissions unit (including the control 

device and associated capture system) to its normal or usual manner of 

operation as expeditiously as practicable in accordance with good air 

pollution control practices for minimizing emissions. The response shall

include minimizing the period of any startup, shutdown or malfunction 

and taking any necessary corrective actions to restore normal operation 

and prevent the likely recurrence of the cause of an excursion or 

exceedance (other than those caused by excused startup or shutdown 

conditions). Such actions may include initial inspection and evaluation, 

recording that operations returned to normal without operator action (such 

as through response by a computerized distribution control system), or any

necessary follow-up actions to return operation to within the indicator 

range, designated condition, or below the applicable emission limitation or 

standard, as applicable.

b. Determination of whether the permittee has used acceptable procedures in 

response to an excursion or exceedance will be based on information 

available, which may include but is not limited to monitoring results, 

review of operation and maintenance procedures and records, and 

inspection of the control device, associated capture system, and the 
Page 37 of 62

process.

7. If the permittee identifies a failure to achieve compliance with an emission 

limitation or standard for which the approved monitoring did not provide an 

indication of an excursion or exceedance while providing valid data, or the results 

of compliance or performance testing document a need to modify the existing 

indicator ranges or designated conditions, the permittee shall promptly notify 

NNEPA and, if necessary, submit a proposed modification to this permit to 

address the necessary monitoring changes. Such a modification may include, but 

is not limited to, reestablishing indicator ranges or designated conditions, 

modifying the frequency of conducting monitoring and collecting data, or the 

monitoring of additional parameters. [40 CFR § 64.7(e)]

8. Based on the results of a determination made under Condition II.N.6.b of this 

permit, NNEPA may require the permittee to develop and implement a Quality 

Improvement Plan (QIP). In addition, NNEPA may require the implementation of 

a QIP if an accumulation of exceedances or excursions exceeds 5 percent duration 

of each unit’s (U1-U3) operating time for one calendar quarter. [40 CFR § 

64.8(a)]

9. Reporting and Recordkeeping Requirements [40 CFR § 64.9]

a. A report for monitoring under this permit shall include, at a minimum, the

information required under Condition III.C of this permit and the 

following information, as applicable [40 CFR § 64.9(a)(2)]:

(i) Summary information on the number, duration and cause

(including unknown cause, if applicable) of excursions or 

exceedances, as applicable, and the corrective actions taken;

(ii) Summary information on the number, duration and cause 

(including unknown cause, if applicable) for monitor downtime 

incidents (other than downtime associated with zero and span or 

other daily calibration checks, if applicable); and

(iii) A description of the actions taken to implement a QIP during the 

reporting period as specified in 40 CFR § 64.8. Upon completion 

of a QIP, the permittee shall include in the next summary report 

documentation that the implementation of the plan has been 

completed and reduced the likelihood of similar levels of 

excursions or exceedances occurring.

b. The permittee shall comply with the recordkeeping requirements specified 

in Condition III.B of this permit. The permittee shall maintain records of 

monitoring data, monitor performance data, corrective actions taken, any 

written QIP required pursuant to 40 CFR § 64.8 and any activities 

undertaken to implement a QIP, and other supporting information required 
Page 38 of 62

to be maintained under 40 CFR Part 64 (such as data used to document the 

adequacy of monitoring or records of monitoring maintenance or 

corrective actions) [40 CFR § 64.9(b)(1)].

c. Instead of paper records, the permittee may maintain records on 

alternative media, such as microfilm, computer files, magnetic tape disks, 

or microfiche, provided that the use of such alternative media allows for 

expeditious inspection and review, and does not conflict with other 

applicable recordkeeping requirements [40 CFR § 64.9(b)(2)].

II.O. Requirements for Reagent Handling Systems [40 CFR §§ 49.151-161]

Pursuant to Tribal Minor NSR Permit #T-0004-NN, issued on August 26, 2015, the 

permittee shall comply with the following requirements for the powdered activated 

carbon (PAC) and calcium bromide handling systems:

1. Vehicle miles travel (VMT) for truck traffic associated with the delivery of PAC 

shall not exceed 30 VMT per 12-month period.

2. VMT for truck traffic associated with the delivery of calcium bromide shall not 

exceed 365 VMT per 12-month period.

3. The permittee shall monitor and maintain records on a calendar month basis of 

each PAC deliver, the VMT of each delivery, and determine the 12-month rolling 

total.

4. The permittee shall monitor and maintain records on a calendar month basis of 

each calcium bromide deliver, the VMT of each delivery, and determine the 12-

month rolling total.

5. At least once during each calendar week, the permittee shall perform a visible 

emissions survey for each PAC silo (Silos A and B). The survey shall be 

performed during daylight hours by an individual trained in EPA Method 22 

while the equipment is in operation. If visible emissions are detected during the 

survey, the permittee shall take corrective action so that within 24 hours no visible 

emissions are detected.

II.P. Operational Flexibility 

1. Clean Air Act Section 502(b)(10) Changes [40 CFR § 71.6(a)(13)(i)] [NNOPR 

§ 404(A)]

a. The permittee may make Clean Air Act Section 502(b)(10) changes 

without applying for a permit revision if those changes do not cause the 

facility to exceed emissions allowable under this permit (whether 

expressed as a rate of emissions or in terms of total emissions) and are not 
Page 39 of 62

modifications under Title I of the Clean Air Act. This class of changes 

does not include: 

(i) Changes that would violate applicable requirements (as defined in 

40 CFR § 71.2, NNOPR § 102(11)); or 

(ii) Changes that would contravene federally enforceable permit terms 

and conditions that are monitoring (including test methods), 

recordkeeping, reporting, or compliance certification requirements. 

b. For each proposed Clean Air Act Section 502(b)(10) change, the permittee 

shall provide written notification to the Director and the Administrator at 

least 7 days in advance of the proposed change. Such notice shall state 

when the change will occur and shall describe the change, any resulting 

emissions change, and any permit terms or conditions made inapplicable 

as a result of the change. The permittee shall attach each notice to its copy 

of this permit.

c. Any permit shield provided in this permit shall not apply to any change 

made pursuant to Condition II.P.1.
Page 40 of 62

III. Facility-Wide or Generic Permit Requirements

Conditions in this section of the permit (Section III) apply to all emissions units located at 

the facility [See 40 CFR § 71.6(a)(1)].

III.A. Testing Requirements [40 CFR § 71.6(a)(3)]

In addition to the unit-specific testing requirements derived from the applicable 

requirements for each individual unit contained in Section II of this permit, the permittee

shall comply with the following generally applicable testing requirements as necessary to 

ensure that the required tests are sufficient for compliance purposes:

1. Submit to NNEPA a source test plan 30 days prior to any required testing. The 

source test plan shall include and address the following elements:

1.0 Purpose of the Test

2.0 Source Description and Mode of Operation During Test

3.0 Scope of Work Planned for Test

4.0 Schedule/Dates

5.0 Process Data to be Collected During Test

6.0 Sampling and Analysis Procedures 

6.1 Sampling Locations

6.2 Test Methods 

6.3 Analysis Procedures and Laboratory Identification

7.0 Quality Assurance Plan 

7.1 Calibration Procedures and Frequency

7.2 Sample Recovery and Field Documentation

7.3 Chain of Custody Procedures

7.4 QA/QC Project Flow Chart

8.0 Data Processing and Reporting 

8.1 Description of Data Handling and QC Procedures

8.2 Report Content

2. Unless otherwise specified by an applicable requirement or permit condition in 

Section II, all source tests shall be performed at maximum operating rates (90% to 

110% of device design capacity).

3. Only regular operating staff may adjust the processes or emission control device 

parameters within two (2) hours before or during a compliance source test. All 

adjustments must be logged and a copy of the log submitted with the test report. 

No adjustments are to be made within two (2) hours before the start of the tests or 

during a test, if those adjustments are a result of consultation before or during the 

tests with source testing personnel, equipment vendors, or consultants. Such 

adjustments may render the source test invalid.
Page 41 of 62

4. During each test run and for two (2) hours prior to the test and two (2) hours after 

the completion of the test, the permittee shall record the following information:

a. Visible emissions or COMS data; and

b. All parametric data which is required to be monitored in Section II for the 

emission unit being tested.

5. Each source test shall consist of at least three (3) valid test runs and the emission 

results shall be reported as the arithmetic average of all valid test runs and in the 

terms of the emission limit. There must be at least 3 valid test runs, unless 

otherwise specified. 

6. Source test reports shall be submitted to NNEPA and U.S. EPA within 60 days of 

completing any required source test.

III.B. Recordkeeping Requirements [40 CFR § 71.6(a)(3)(ii)] 

In addition to the unit-specific recordkeeping requirements derived from the applicable 

requirements for each individual unit and contained in Section II, the permittee shall 

comply with the following generally applicable recordkeeping requirements: 

1. The permittee shall keep records of required monitoring information that include 

the following: 

a. The date, place, and time of sampling or measurements; 

b. The date(s) analyses were performed; 

c. The company or entity that performed the analyses; 

d. The analytical techniques or methods used; 

e. The results of such analyses; and 

f. The operating conditions existing at the time of the sampling or 

measurement. 

2. The permittee shall retain records of all required monitoring data and support 

information for a period of at least 5 years from the date of the monitoring 

sample, measurement, report, or application. Support information includes all 

calibration and maintenance records, all original strip-chart recordings for 

continuous monitoring instrumentation, and copies of all reports required by this 

permit.
Page 42 of 62

3. The permittee shall maintain a file of all measurements, including continuous 

monitoring system, monitoring device, and performance testing measurements; all 

continuous monitoring system performance evaluations; all continuous 

monitoring system or monitoring device calibration checks; adjustments and 

maintenance performed on these systems or devices; and all other information 

required by 40 CFR Part 60 recorded in a permanent form suitable for inspection. 

The file shall be retained for at least five years following the date of such 

measurements, maintenance, reports and records [40 CFR § 71.6(a)(3)(ii), 40 

CFR § 60.7(f)].

III.C. Reporting Requirements [40 CFR § 71.6 (a)(3)(iii)] 

1. The permittee shall submit to NNEPA and EPA Region 9 reports of any 

monitoring required under 40 CFR § 71.6(a)(3)(i)(A), (B), or (C) each six month 

reporting period from January 1 to June 30 and from July 1 to December 31. All 

reports shall be submitted to NNEPA and US EPA and shall be postmarked by the 

30th day following the end of the reporting period. All instances of deviations 

from permit requirements must be clearly identified in such reports. All required 

reports must be certified by a responsible official consistent with Condition 

III.C.4 of this permit.

a. A monitoring report under this section must include the following: 

(i) The company name and address.

(ii) The beginning and ending dates of the reporting period.

(iii) The emissions unit or activity being monitored.

(iv) The emissions limitation or standard, including operational 

requirements and limitations (such as parameter ranges), specified 

in the permit for which compliance is being monitored. 

(v) All instances of deviations from permit requirements, including 

those attributable to upset conditions and exceedances as defined 

under 40 CFR § 64.1, and the date on which each deviation 

occurred. 

(vi) If the permit requires continuous monitoring of an emissions limit 

or parameter range, the report must include the total operating time 

of the emissions unit during the reporting period, the total duration 

of excess emissions or parameter exceedances during the reporting 

period, and the total downtime of the continuous monitoring 

system during the reporting period. 
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(vii) If the permit requires periodic monitoring, visual observations, 

work practice checks, or similar monitoring, the report shall 

include the total time when such monitoring was not performed 

during the reporting period and at the source's discretion either the 

total duration of deviations indicated by such monitoring or the 

actual records of deviations. 

(viii) All other monitoring results, data, or analyses required to be 

reported by the applicable requirement. 

(ix) The name, title, and signature of the responsible official who is 

certifying to the truth, accuracy, and completeness of the report. 

b. Any report required by an applicable requirement that provides the same 

information described in Condition III.C.1.a.(i) through (ix) above shall 

satisfy the requirement under Condition III.C.1.a.

c. "Deviation," means any situation in which an emissions unit fails to meet 

a permit term or condition. A deviation is not always a violation. A 

deviation can be determined by observation or through review of data 

obtained from any testing, monitoring, or record keeping established in 

accordance with 40 CFR §§ 71.6(a)(3)(i) and (a)(3)(ii). For a situation 

lasting more than 24 hours, each 24-hour period is considered a separate 

deviation. Included in the meaning of deviation are any of the following: 

(i) A situation when emissions exceed an emission limitation or 

standard; 

(ii) A situation where process or emissions control device parameter 

values indicate that an emission limitation or standard has not been 

met; 

(iii) A situation in which observations or data collected demonstrate 

noncompliance with an emission limitation or standard or any 

work practice or operating condition required by the permit. 

(iv) A situation in which an exceedance or excursion, as defined in 40 

CFR § 64.1, occurs. 

2. The permittee shall promptly report to the NNEPA and EPA Regional Office 

deviations from permit requirements, including those attributable to upset 

conditions, the probable cause of such deviations, and any corrective actions or 

preventive measures taken. Where the underlying applicable requirement contains 

a definition of “prompt” or otherwise specifies a time frame for reporting 

deviations, that definition or time frame shall govern.
Page 44 of 62

Where the underlying applicable requirement does not define prompt or provide a 

timeframe for reporting deviations, reports of deviations will be submitted based 

on the following schedule: 

a. For emissions of a hazardous air pollutant or a toxic air pollutant (as 

identified in the applicable regulation) that continue for more than an hour 

in excess of permit requirements, the report must be made by telephonic, 

verbal, or facsimile communication within 24 hours of the occurrence. 

b. For emissions of any regulated pollutant, excluding a hazardous air 

pollutant or a toxic air pollutant, that continue for more than two hours in 

excess of permit requirements, the report must be made by telephonic, 

verbal, or facsimile communication within 48 hours of the occurrence. 

c. For all other deviations from permit requirements, the report shall be 

submitted with the semi-annual monitoring report required in Condition

III.C.1 of this permit. 

3. If any of the conditions in Condition III.C.2.a or b of this permit are met, the 

source must notify NNEPA and US EPA by telephone, facsimile, or electronic 

mail sent to tbbegay@navajo-nsn.gov and AEO_R9@epa.gov, based on the 

timetable listed. A written notice, certified consistent with Condition III.C.4 of 

this permit, must be submitted within 10 working days of the occurrence. All 

deviations reported under this section must also be identified in the 6-month 

report required under Condition III.C.1. 

4. Any application form, report, or compliance certification required to be submitted 

by this permit shall contain certification by a responsible official of truth, 

accuracy, and completeness. All certifications shall state that, based on 

information and belief formed after reasonable inquiry, the statements and 

information in the document are true, accurate, and complete. 

III.D. Protection of Stratospheric Ozone [40 CFR Part 82]

1. The permittee shall comply with the standards for labeling of products using 

ozone-depleting substances pursuant to 40 CFR Part 82, Subpart E:

a. All containers in which a class I or class II substance is stored or 

transported, all products containing a class I substance, and all products 

directly manufactured with a Class I substance being introduced into 

interstate commerce must bear warning statements that comply with the 

requirements in 40 CFR § 82.106(a). [40 CFR § 82.124(a)(1)(i)]

b. On January 1, 2015, or any time between May 15, 1993 and January 1, 

2015 that the Administrator determines for a particular product 

manufactured with or containing a class II substance that there are 
Page 45 of 62

substitute products or manufacturing processes for such product that do 

not rely on the use of a class I or class II substance, that reduce the overall 

risk to human health and the environment, and that are currently or 

potentially available, no product identified in 40 CFR § 82.102(b) may be 

introduced into interstate commerce unless it bears a warning statement 

that complies with the requirements of 40 CFR § 82.106, unless such 

labeling is not required under 40 CFR §§ 82.106(b), 82.112(c) or (d), 

82.116(a) or 82.118(a). [40 CFR § 82.124(a)(1)(ii)]

c. The placement of the required warning statement must comply with the 

requirements of 40 CFR § 82.108. [40 CFR § 82.124(a)(2)(i)]

d. The form of the label bearing the required warning statement must comply 

with the requirements of 40 CFR § 82.110. [40 CFR § 82.124(a)(3)(i)]

e. No person may modify, remove, or interfere with the required warning 

statement except as described in 40 CFR § 82.112. [40 CFR §

82.124(a)(4)]

2. The permittee shall comply with the standards for recycling and emissions

reduction pursuant to 40 CFR Part 82, Subpart F, except as provided for motor 

vehicle air conditioners (MVACs) in Subpart B [40 CFR § 82.150(b)]:

a. Persons opening appliances for maintenance, service, repair, or disposal 

must comply with the required practices pursuant to 40 CFR § 82.156.

b. Equipment used during maintenance, service, repair, or disposal of 

appliances must comply with the standards for recycling and recovery 

equipment pursuant to 40 CFR § 82.158.

c. Persons performing maintenance, service, repair, or disposal of appliances 

must be certified by an approved technician certification program pursuant 

to 40 CFR § 82.161.

d. Persons disposing of small appliances, MVACs, and MVAC-like 

appliances (as defined in 40 CFR § 82.152) must comply with 

recordkeeping requirements pursuant to 40 CFR § 82.166. 

e. Persons owning commercial or industrial process refrigeration equipment 

must comply with the leak repair requirements pursuant to 40 CFR §

82.156. 

f. Owners/operators of appliances normally containing 50 or more pounds of 

refrigerant must keep records of when the refrigerant was purchased and 

added to such appliances pursuant to 40 CFR § 82.166.
Page 46 of 62

3. If the permittee produces, transforms, destroys, imports, or exports a Class I or 

Class II controlled substance, the permittee is subject to all the requirements in 40 

CFR Part 82, Subpart A, Production and Consumption Controls [40 CFR §

82.1(b)].

4. If the permittee performs a service on a motor (fleet) vehicle when this service 

involves ozone-depleting substance refrigerant (or regulated substitute substance) 

in the MVAC, the permittee is subject to all the applicable requirements specified 

in 40 CFR Part 82, Subpart B, Servicing of Motor Vehicle Air Conditioners [40 

CFR § 82.30(b)].

The term "motor vehicle" as used in Subpart B does not include a vehicle in 

which final assembly of the vehicle has not been completed. The term "MVAC" 

as used in Subpart B does not include the air-tight sealed refrigeration system 

used for refrigerated cargo or system used on passenger buses using HCFC-22 

refrigerant [40 CFR § 82.32(c), (d)].

5. The permittee shall be allowed to switch from any ozone-depleting substance to 

any acceptable substitute that is listed in the Significant New Alternatives 

Program (SNAP) promulgated pursuant to 40 CFR Part 82, Subpart G.

III.E. Asbestos from Demolition and Renovation [40 CFR Part 61, Subpart M]

The permittee shall comply with the requirements of 40 CFR §§ 61.140 through 61.157 

of the National Emission Standard for Asbestos for all demolition and renovation projects

[40 CFR § 61.140].

III.F. Compliance Schedule [40 CFR §§ 71.5(c)(8)(iii) and 71.6(c)(3)]

1. For applicable requirements with which the source is in compliance, the source 

will continue to comply with such requirements. 

2. For applicable requirements that will become effective during the permit term, the 

source shall meet such requirements on a timely basis.
Page 47 of 62

IV. Title V Administrative Requirements

IV.A. Fee Payment [NNOPR Subpart VI] [40 CFR § 71.6(a)(7) and § 71.9]

1. The permittee shall pay an annual permit fee in accordance with the procedures 

outlined below. [NNOPR §§ 603(A) and (B)]

a. The permittee shall pay the annual permit fee by April 1 of each year.

b. Fee payments shall be remitted in the form of a money order or certified 

check made payable to the Navajo Nation Environmental Protection 

Agency.

c. The permittee shall send the fee payment to:

Navajo Nation EPA Air Quality Control Program

Operating Permit Program 

P.O. Box 529 

Fort Defiance, AZ 86504

2. The permittee shall submit a fee calculation worksheet form with the annual 

permit fee by April 1 of each year. Calculations of actual or estimated emissions 

and calculation of the fees owed shall be computed on the fee calculation 

worksheets provided by US EPA. Fee payment of the full amount must 

accompany each fee calculation worksheet. [40 CFR § 71.6(a)(7) and §

71.9(h)(1)] 

3. The fee calculation worksheet shall be certified by a responsible official 

consistent with 40 CFR § 71.5(d). [40 CFR § 71.6(a)(7) and § 71.9(h)(2)]

4. Basis for calculating annual fee:

The annual emissions fee shall be calculated by multiplying the total tons of 

actual emissions of all fee pollutants emitted from the source by the applicable 

emissions fee (in dollars/ton) in effect at the time of calculation. Emissions of any 

regulated air pollutant that already are included in the fee calculation under a 

category of regulated pollutant, such as a federally listed hazardous air pollutant 

that is already accounted for as a VOC or as PM10, shall be counted only once in 

determining the source’s actual emissions. [NNOPR §§ 602(A) and (B)(1)]

a. “Actual emissions” means the actual rate of emissions in tpy of any fee 

pollutant emitted from a part 71 source over the preceding calendar year. 

Actual emissions shall be calculated using each emissions unit’s actual 

operating hours, production rates, in-place control equipment, and types of 

materials processed, stored, or combusted during the preceding calendar 

year. Actual emissions shall not include emissions of any one fee pollutant 
Page 48 of 62

in excess of 4,000 TPY, or any emissions that come from insignificant 

activities [NNOPR § 102(5)].

b. Actual emissions shall be computed using methods required by the permit 

for determining compliance, such as monitoring or source testing data [40 

CFR § 71.6(a)(7) and § 71.9(h)(3)].

c. If actual emissions cannot be determined using the compliance methods in 

the permit, the permittee shall use other federally recognized procedures 

[40 CFR § 71.6(a)(7) and § 71.9(e)(2)].

d. The term “fee pollutant” is defined in NNOPR § 102(24).

e. The term “regulated air pollutant” is defined in NNOPR § 102(50), except 

that for purposes of this permit the term does not include any pollutant that 

is regulated solely pursuant to 4 N.N.C. § 1121 nor does it include any 

hazardous air pollutant designated by the Director pursuant to 4 N.N.C. § 

1126(B).

f. The permittee should note that the applicable fee is revised each year to 

account for inflation, and it is available from NNEPA starting on March 1 

of each year. 

g. The total annual fee due shall be the greater of the applicable minimum fee 

and the sum of subtotal annual fees for all fee pollutants emitted from the 

source. [NNOPR § 602(B)(2)]

5. The permittee shall retain, in accordance with the provisions of 40 CFR §

71.6(a)(3)(ii), all fee calculation worksheets and other emissions-related data used 

to determine fee payment for 5 years following submittal of fee payment. 

Emission-related data include emissions-related forms provided by NNEPA and 

used by the permittee for fee calculation purposes, emissions-related spreadsheets, 

and records of emissions monitoring data and related support information required 

to be kept in accordance with 40 CFR § 71.6(a)(3)(ii) [40 CFR § 71.6(a)(7) and §

71.9(i)].

6. Failure of the permittee to pay fees in a timely manner shall subject the permittee

to assessment of penalties and interest in accordance with NNOPR § 603(C).

7. When notified by NNEPA of underpayment of fees, the permittee shall remit full 

payment within 30 days of receipt of notification [40 CFR § 71.9(j)(2)].

8. A permittee who thinks an NNEPA assessed fee is in error and wishes to 

challenge such fee, shall provide a written explanation of the alleged error to 

NNEPA along with full payment of the NNEPA assessed fee. Within 90 days of 

receipt of the correspondence, NNEPA shall review the data to determine whether 
Page 49 of 62

the assessed fee was in error. If an error was made, the overpayment shall be 

credited to the account of the permittee. [40 CFR § 71.9(j)(3)].

IV.B. Blanket Compliance Statement [CAA §§113(a) and 113(e)(1) and 40 CFR § 51.212(c), 

§ 52.12(c), § 52.33, § 60.11(g), § 61.12(e), § 71.6(a)(6)(i) and (ii), and § 71.12]

1. The permittee must comply with all conditions of this Part 71 permit. Any permit 

noncompliance, including, but not limited to, violation of any applicable 

requirement; any permit term or condition; any fee or filing requirement; any duty 

to allow or carry out inspection, entry, or monitoring activities; or any regulation 

or order issued pursuant to 40 CFR Part 71 constitutes a violation of the Clean Air 

Act and is grounds for enforcement action; permit termination, revocation and 

reissuance, or modification; or denial of a permit renewal application. It shall not 

be a defense for a permittee in an enforcement action that it would have been 

necessary to halt or reduce the permitted activity in order to maintain compliance 

with the conditions of this permit [CAA § 113(a); 40 CFR §§ 71.6(a)(6)(i) and 

(ii), 71.12].

2. Determinations of deviations, continuous or intermittent compliance status, or 

violations of this permit are not limited to the applicable testing or monitoring 

methods required by the underlying regulations or this permit; other credible 

evidence (including any evidence admissible under the Federal Rules of 

Evidence) must be considered in such determinations. [CAA § 113(a) and 

113(e)(1); 40 CFR § 51.212(c), § 52.12(c), § 52.33, § 60.11(g), and § 61.12(e)]

IV.C. Compliance Certifications [40 CFR § 71.6(c)(1), (5)] [NNOPR § 302(I)] 

1. The permittee shall submit to NNEPA and US EPA Region 9 a semi-annual 

certification of compliance with permit terms and conditions, including emission 

limitations, standards, or work practices, postmarked by January 31 and July 31 of 

each year and covering the previous six-month period ending on December 31 

and June 30, respectively. The compliance certification shall be certified as to 

truth, accuracy, and completeness by the permit-designated responsible official 

consistent with Condition III.C.4 of this permit [40 CFR § 71.6(c)(1), (5)].

2. The certification shall include the following [40 CFR § 71.6(c)(5)(iii)]:

a. Identification of each permit term or condition that is the basis of the 

certification.

b. Identification of the method(s) or other means used for determining the 

compliance status of each term and condition during the certification 

period, and whether such methods or other means provide continuous or 

intermittent data.

c. The compliance status of each term and condition of the permit for the 

period covered by the certification based on the method or means 
Page 50 of 62

designated above. The certification shall identify each deviation and take 

it into account in the compliance certification. The certification shall 

identify as possible exceptions to compliance any periods during which 

compliance is required but an excursion or exceedance has occurred 

pursuant to this permit.

d. Whether compliance with each permit term was continuous or 

intermittent.

e. If necessary, the permittee also shall identify any other material 

information that must be included in the certification to comply with 

Section 113(c)(2) of the Clean Air Act, which prohibits knowingly 

making a false certification or omitting material information.

IV.D. Duty to Provide and Supplement Information [40 CFR § 71.6(a)(6)(v), 40 CFR §

71.5(b)]

The permittee shall furnish to NNEPA and US EPA Region 9, within a reasonable time, 

any information that NNEPA and US EPA Region 9 may request in writing to determine 

whether cause exists for modifying, revoking and reissuing, or terminating the permit, or 

to determine compliance with the permit. Upon request, the permittee shall also furnish 

to NNEPA and US EPA Region 9 copies of records that are required to be kept pursuant 

to the terms of the permit, including information claimed to be confidential. Information 

claimed to be confidential should be accompanied by a claim of confidentiality according 

to the provisions of 40 CFR Part 2, Subpart B. The permittee, upon becoming aware that 

any relevant facts were omitted or incorrect information was submitted in the permit 

application, shall promptly submit such supplementary facts or corrected information. 

The permittee shall also provide additional information as necessary to address any 

requirements that become applicable to the facility after this permit is issued.

IV.E. Submissions [40 CFR § 71.5(d), § 71.6(a)(iii)(A) and (c)(1), and § 71.9(h)(2)]

Any document required to be submitted with this permit shall be certified by a 

responsible official as to truth, accuracy, and completeness. Such certifications shall 

state that based on information and belief formed after reasonable inquiry, the statements 

and information in the document are true, accurate, and complete. 

All documents required to be submitted, including reports, test data, monitoring data, 

notifications, compliance certifications, fee calculation worksheets, and applications for 

renewals and permit modifications shall be submitted to NNEPA and US EPA Region 9:

Navajo Nation Air Quality Control Program

Operating Permit Program 

P.O. Box 529 

Fort Defiance, AZ 86504
Page 51 of 62

and

Director, Air Division (Attn: AIR-1)

EPA Region IX

75 Hawthorne Street

San Francisco, CA 94105

IV.F. Severability Clause [40 CFR § 71.6(a)(5)]

The provisions of this permit are severable, and in the event of any challenge to any 

portion of this permit, or if any portion is held invalid, the remaining permit conditions 

shall remain valid and in force.

IV.G. Permit Actions [40 CFR § 71.6(a)(6)(iii)]

This permit may be modified, revoked, reopened, and reissued, or terminated for cause. 

The filing of a request by the permittee for a permit modification, revocation and 

reissuance, or termination, or of a notification of planned changes or anticipated 

noncompliance, does not stay any permit condition.

IV.H Administrative Permit Amendments [40 CFR § 71.7(d)] [NNOPR § 405(C)]

The permittee may implement the changes outlined in subparagraphs (1) through (5)

below immediately upon submittal of the request for the administrative revision. The 

permittee may request the use of administrative permit amendment procedures for a 

permit revision that: 

1. Corrects typographical errors. 

2. Identifies a change in the name, address, or phone number of any person 

identified in the permit, or provides a similar minor administrative change at the 

source. 

3. Requires more frequent monitoring or reporting by the permittee. 

4. Allows for a change in ownership or operational control of a source where the 

NNEPA determines that no other change in the permit is necessary, provided that

a written agreement containing a specific date for transfer of permit 

responsibility, coverage, and liability between the current and new permittee has 

been submitted to the NNEPA;

5. Incorporates into the Part 71 permit the requirements from preconstruction review 

permits authorized under an EPA-approved program, provided that such a 

program meets procedural requirements substantially equivalent to the 

requirements of 40 CFR §§ 71.7, 71.8 and 71.10 that would be applicable to the 
Page 52 of 62

change if it were subject to review as a permit modification, and compliance 

requirements substantially equivalent to those contained in 40 CFR § 71.6. 

6. Incorporates any other type of change which NNEPA has determined to be similar 

to those listed above in subparagraphs (1) through (5). 

IV.I. Minor Permit Modifications [40 CFR § 71.7(e)(1)] [NNOPR § 405(D)]

1. The permittee may request the use of minor permit modification procedures only 

for those modifications that: 

a. Do not violate any applicable requirement. 

b. Do not involve significant changes to existing monitoring, reporting, or 

recordkeeping requirements in this permit. 

c. Do not require or change a case-by-case determination of an emissions

limitation or other standard, or a source-specific determination for 

temporary sources of ambient impacts, or a visibility or increment 

analysis. 

d. Do not seek to establish or change a permit term or condition for which 

there is no corresponding underlying applicable requirement and that the 

permittee has assumed to avoid an applicable requirement to which the 

permittee would otherwise be subject. Such terms and conditions include: 

(i) A federally enforceable emissions cap assumed to avoid 

classification as a modification under any provision of Clean Air 

Act Title I; and 

(ii) An alternative emissions limit approved pursuant to regulations 

promulgated under Section 112(i)(5) of the Clean Air Act. 

e. Are not modifications under any provision of Title I of the Clean Air Act. 

f. Are not required to be processed as a significant modification. 

2. Notwithstanding the list of changes eligible for minor permit modification 

procedures in paragraph (1) above, minor permit modification procedures may be 

used for permit modifications involving the use of economic incentives, 

marketable permits, emissions trading, and other similar approaches, to the extent 

that such minor permit modification procedures are explicitly provided for in an 

applicable implementation plan or in applicable requirements promulgated by 

EPA. 
Page 53 of 62

3. An application requesting the use of minor permit modification procedures shall 

meet the requirements of 40 CFR § 71.5(c) and shall include the following: 

a. A description of the change, the emissions resulting from the change, and 

any new applicable requirements that will apply if the change occurs; 

b. The permittee's suggested draft permit; 

c. Certification by a responsible official, consistent with 40 CFR § 71.5(d), 

that the proposed modification meets the criteria for use of minor permit 

modification procedures and a request that such procedures be used; and 

d. Completed forms for NNEPA and US EPA to use to notify affected States 

as required under 40 CFR § 71.8. 

e. If the requested permit revision would affect existing compliance plans or 

schedules, related progress reports, or certification of compliance 

requirements, and an outline of such effects.

4. The permittee may make the change proposed in its minor permit modification 

application immediately after submittal of such application. After the permittee

makes the change allowed by the preceding sentence, and until NNEPA takes any 

of the actions specified in NNOPR § 405(D)(6)(a) through (c), the permittee must 

comply with both the applicable requirements governing the change and the 

proposed permit terms and conditions. During this time period, the permittee need 

not comply with the existing permit terms and conditions it seeks to modify. 

However, if the permittee fails to comply with its proposed permit terms and 

conditions during this period, the existing permit terms and conditions it seeks to 

modify may be enforced against it.

5. The permit shield under 40 CFR § 71.6(f) may not extend to minor permit 

modifications [40 CFR § 71.7(e)(1)(vi)]. 

IV.J. Group Processing of Minor Permit Modifications [40 CFR § 71.7(e)(2)] 

1. Group processing of modifications by NNEPA may be used only for those permit 

modifications: 

a. That meet the criteria for minor permit modification procedures under 

Condition IV.I.1 of this permit; and 

b. That collectively are below the threshold level of 10 percent of the 

emissions allowed by the permit for the emissions unit for which the 

change is requested, 20 percent of the applicable definition of major 

source in 40 CFR § 71.2, or 5 tons per year, whichever is least. 
Page 54 of 62

2. An application requesting the use of group processing procedures shall meet the 

requirements of 40 CFR § 71.5(c) and shall include the following: 

a. A description of the change, the emissions resulting from the change, and 

any new applicable requirements that will apply if the change occurs. 

b. The permittee's suggested draft permit. 

c. Certification by a responsible official, consistent with 40 CFR § 71.5(d), 

that the proposed modification meets the criteria for use of group 

processing procedures and a request that such procedures be used. 

d. A list of the permittee's other pending applications awaiting group 

processing, and a determination of whether the requested modification, 

aggregated with these other applications, equals or exceeds the threshold 

set under Condition IV.J.1.b above. 

e. Certification that the permittee has notified US EPA of the proposed 

modification. Such notification need only contain a brief description of 

the requested modification.

f. Completed forms for NNEPA to use to notify affected States as required 

under 40 CFR § 71.8 and US EPA as required under 40 CFR § 71.10(d). 

3. The permittee may make the changes proposed in its minor permit modification 

application immediately after it files such application. After the source makes the 

changes allowed by the preceding sentence, and until NNEPA takes any of the 

actions specified in NNOPR § 405(D)(6)(a) through (c), the permittee must 

comply with both the applicable requirements governing the change and the 

proposed permit terms and conditions. During this time period, the permittee need 

not comply with the existing permit terms and conditions it seeks to modify. 

However, if the permittee fails to comply with its proposed permit terms and 

conditions during this time period, the existing permit terms and conditions it 

seeks to modify may be enforced against it. 

4. The permit shield under 40 CFR § 71.6(f) may not extend to group processing of 

minor permit modifications [40 CFR § 71.7(e)(2)(vi)]. 

IV.K. Significant Permit Modifications [40 CFR § 71.7(e)(3)] [NNOPR § 405(E)]

1. The permittee must request the use of significant permit modification procedures 

for those modifications that: 

a. Do not qualify as minor permit modifications or as administrative 

amendments. 
Page 55 of 62

b. Are significant changes in existing monitoring permit terms or conditions. 

c. Are relaxations of reporting or recordkeeping permit terms or conditions. 

2. Nothing herein shall be construed to preclude the permittee from making changes 

consistent with Part 71 that would render existing permit compliance terms and 

conditions irrelevant. 

3. The permittee must meet all requirements of Part 71 for applications for 

significant permit modifications. For the application to be determined complete, 

the permittee must supply all information that is required by 40 CFR § 71.5(c) for 

permit issuance and renewal, but only that information that is related to the 

proposed change [40 CFR §§ 71.7(e)(3)(ii) and 71.5(a)(2)].

IV.L. Reopening for Cause [40 CFR § 71.7(f)]

NNEPA shall reopen and revise the permit prior to expiration under any of the following 

circumstances:

1. Additional applicable requirements under the Clean Air Act become applicable to 

a major Part 71 source with a remaining permit term of 3 or more years.

2. Additional requirements (including excess emissions requirements) become 

applicable to an affected source under the acid rain program. Upon approval by 

the Administrator, excess emissions offset plans shall be deemed to be 

incorporated into the permit. 

3. NNEPA or US EPA determines that the permit contains a material mistake or that 

inaccurate statements were made in establishing the emissions standards or other 

terms or conditions of the permit.

4. NNEPA or US EPA determines that the permit must be revised or revoked to 

assure compliance with the applicable requirements.

IV.M. Property Rights [40 CFR § 71.6(a)(6)(iv)]

This permit does not convey any property rights of any sort, or any exclusive privilege.

IV.N. Inspection and Entry [40 CFR § 71.6(c)(2)]

Upon presentation of credentials and other documents as may be required by law, the 

permittee shall allow authorized representatives from NNEPA and US EPA to perform 

the following:
Page 56 of 62

1. Enter upon the permittee’s premises where a Part 71 source is located or 

emissions-related activity is conducted, or where records must be kept under the 

conditions of this permit;

2. Have access to and copy, at reasonable times, any records that must be kept under 

the conditions of this permit;

3. Inspect at reasonable times any facilities, equipment (including monitoring and air 

pollution control equipment), practices, or operations regulated or required under 

the permit; and

4. As authorized by the Clean Air Act, sample or monitor at reasonable times 

substances or parameters for the purpose of assuring compliance with the permit 

or applicable requirements.

IV.O. Emergency Provisions [40 CFR § 71.6(g)]

1. In addition to any emergency or upset provision contained in any applicable 

requirement, the permittee may seek to establish that noncompliance with a 

technology-based emission limitation under this permit was due to an emergency. 

To do so, the permittee shall demonstrate the affirmative defense of emergency 

through properly signed, contemporaneous operating logs, or other relevant 

evidence that: 

a. an emergency occurred and that the permittee can identify the cause(s) of 

the emergency; 

b. the permitted facility was at the time being properly operated; 

c. during the period of the emergency the permittee took all reasonable steps 

to minimize levels of emissions that exceeded the emissions standards, or 

other requirements in this permit; and 

d. the permittee submitted notice of the emergency to NNEPA within 2 

working days of the time when emissions limitations were exceeded due 

to the emergency. This notice must contain a description of the 

emergency, any steps taken to mitigate emissions, and corrective actions 

taken. This notice fulfills the requirements of Condition III.C.2 of this 

permit. 

e. In any enforcement preceding the permittee attempting to establish the 

occurrence of an emergency has the burden of proof. 

2. An "emergency" means any situation arising from sudden and reasonably 

unforeseeable events beyond the control of the permittee, including acts of God, 

which situation requires immediate corrective action to restore normal operation, 
Page 57 of 62

and that causes the source to exceed a technology-based emissions limitation 

under this permit due to unavoidable increases in emissions attributable to the 

emergency. An emergency shall not include noncompliance to the extent caused 

by improperly designed equipment, lack of preventive maintenance, careless or 

improper operation, or operator error. 

IV.P. Transfer of Ownership or Operation [40 CFR § 71.7(d)(1)(iv)]

A change in ownership or operational control of this facility may be treated as an 

administrative permit amendment if the NNEPA determines no other change in this 

permit is necessary and provided that a written agreement containing a specific date for 

transfer of permit responsibility, coverage, and liability between the current and new 

permittee has been submitted to NNEPA.

IV.Q. Off Permit Changes [40 CFR § 71.6(a)(12)] [NNOPR § 404(B)]

The permittee is allowed to make certain changes without a permit revision, provided that 

the following requirements are met:

1. Each change is not addressed or prohibited by this permit;

2. Each change must comply with all applicable requirements and may not violate 

any existing permit term or condition;

3. Changes under this provision may not include changes or activities subject to any 

requirement under 40 CFR Parts 72 through 78 or that are modifications under 

any provision of Title I of the Clean Air Act;

4. The permittee must provide contemporaneous written notice to NNEPA and US 

EPA Region 9 of each change, except for changes that qualify as insignificant 

activities under 40 CFR § 71.5(c)(11). The written notice must describe each 

change, the date of the change, any change in emissions, pollutants emitted and 

any applicable requirements that would apply as a result of the change;

5. The permit shield does not apply to changes made under this provision; and

6. The permittee must keep a record describing all changes that result in emissions 

of any regulated air pollutant subject to any applicable requirement not otherwise 

regulated under this permit, and the emissions resulting from those changes.

IV.R. Permit Expiration and Renewal [40 CFR §§ 71.5(a)(1)(iii), 71.6(a)(11), and 71.7(b) and 

(c)]

1. This permit shall expire upon the earlier occurrence of the following events:

a. five (5) years elapses from the date of issuance; or
Page 58 of 62

b. the source is issued a Part 70 permit by NNEPA, provided that EPA has 

granted the Navajo Nation treatment as a state and primacy for a Part 70 

program and that NNEPA issues the permit consistent with the VCA.

2. Expiration of this permit terminates the permittee’s right to operate unless a 

timely and complete permit renewal application has been submitted on or before a 

date 6 months, but not more than 18 months, prior to the date of expiration of this 

permit. 

3. If the permittee submits a timely and complete permit application for renewal that 

is consistent with 40 CFR § 71.5(a)(2), but NNEPA has failed to issue or deny the 

renewal permit, then the permit shall not expire until the renewal permit has been 

issued or denied and any permit shield granted pursuant to 40 CFR § 71.6(f) may 

extend beyond the original permit term until renewal.

4. The permittee’s failure to have a Part 71 permit is not a violation of 40 CFR Part 

71 until NNEPA takes final action on the permit renewal application. This 

protection shall cease to apply if, subsequent to the completeness determination, 

the permittee fails to submit any additional information identified as being needed 

to process the application by the deadline specified in writing by NNEPA.

5. Renewal of this permit is subject to the same procedural requirements that apply 

to initial permit issuance, including those for public participation and affected 

State and tribal review.

6. The application for renewal shall include the current permit number, description 

of permit revisions and off-permit changes that occurred during the permit term, 

any applicable requirements that were promulgated and not incorporated into the 

permit during the permit term, and other information required by the application 

form.

IV.S. Additional Permit Conditions [Voluntary Compliance Agreement, Article 6]

This permit is issued pursuant to the Voluntary Compliance Agreement between the 

permittee and the Navajo Nation. The permittee shall comply with the terms of this 

permit and shall be subject to enforcement of the permit by the Navajo Nation EPA, 

pursuant to the terms of the Voluntary Compliance Agreement. The permittee’s 

agreement to comply is effective upon the permittee’s written acceptance of the permit 

and expires at the end of the permit term, unless the permit is renewed. The permittee’s 

agreement to comply may be withdrawn during the permit term only if the Voluntary 

Compliance Agreement is terminated or expires as provided in that Agreement.

IV.T. Part 71 Permit Enforcement [Voluntary Compliance Agreement, Section 5.4.5; 40 CFR 

§ 71.12]
Page 59 of 62

1. The Navajo Nation has the authority to:

a. Develop compliance plans and schedules of compliance;

b. Conduct compliance and monitoring activities, including review of 

monitoring reports and compliance certifications, inspections, audits, 

conducting and/or reviewing stack tests, and issuing requests for 

information either before or after a violation is identified; and

c. Conduct enforcement-related activities, including issuance of notices, 

findings, and letters of violation, and development of cases up to, but not 

including, the filing of a complaint or order.

2. Violations of any applicable requirement; any permit term or condition; any fee or 

filing requirement; any duty to allow or carry out inspection, entry, or monitoring 

activities; or any regulation or order issued pursuant to 40 CFR Part 71 are 

violations of the Clean Air Act and are subject to full Federal enforcement 

authorities available under the Clean Air Act. 
Page 60 of 62

Attachment A

Dust Control Plan 
Page 61 of 62

Attachment B

Phase II Acid Rain Permit Renewal 
Page 62 of 62

Attachment C

NESHAP for Coal- and Oil-Fired Electric Utility 

Steam Generating Units, 

40 CFR Part 63, Subpart UUUUU –

Compliance, Monitoring, Testing, Notification, 

Recordkeeping, and Reporting Requirements
Navajo Nation Environmental Protection Agency –Air Quality Control/Operating Permit Program

Post Office Box 529, Fort Defiance, AZ 86504  Bldg. #2837 Route 112

Telephone (928) 729-4096, Fax (928) 729-4313, Email airquality@navajo-nsn.gov

www.navajonationepa.org/airquality.html

Detailed Information 

Permitting Authority: NNEPA

County: Coconino State: Arizona AFS Plant ID: 04-005-N0423

Facility: Navajo Generating Station

Document Type: STATEMENT OF BASIS 

PART 71 FEDERAL OPERATING PERMIT

DRAFT STATEMENT OF BASIS

Navajo Generating Station

Permit No. NN-OP-15-06 

1. Facility Information

a. Permittee

Navajo Generating Station

5 Miles East of Page, off U.S. Highway 98

Page, Arizona 86040

Mailing Address:

P.O. Box 850

Page, Arizona 86040

Managing Participant Name: Salt River Project Agricultural Improvement 

and Power District (SRP)*

Managing Participant Mailing Address: P.O. Box 52025, PAB 352

Phoenix, Arizona 85072-2025

*Note: This facility is co-owned by 6 entities. SRP is listed as the managing 

participant in this permit since it acts as the facility operator, and has accepted the 

responsibility to obtain environmental permits for Navajo Generating Station, including 

an Acid Rain permit and Part 71 Permit. In addition to SRP (21.7%), the other 5 coowners of this facility are:

1. U.S. Bureau of Reclamation (USBR) (24.3%)

2. Los Angeles Department of Water and Power (LADWP) (21.2%)

3. Arizona Public Service Company (APS) (14.0%)

4. Nevada Power Company (NPC) (11.3%)

THE NAVAJO NATION RUSSELL BEGAYE PRES I DENT

JONATHAN NEZ VICE PRESIDENT
Page 2 of 29

5. Tucson Electric Power (TEP) (7.5%)

b. Contact Information

Facility Contact: Paul Ostapuk Phone: (928) 645-6577

O&M Manager Facsimile: (928) 645-7298

 

Responsible Official: Robert K. Talbot Phone: (928) 645-6217

Plant Manager Facsimile: (928) 645-7298

c. Description_of_Operations,_Products

The facility is a 2,250 net Megawatt coal-fired power plant. Bituminous coal is mined by 

Peabody Energy at the Kayenta Mine complex and delivered by electric rail to NGS. 

Coal is then transferred via enclosed conveyor systems to the boilers or to a storage pile 

for later use. 

The management of coal combustion residues and the delivery of limestone for the SO2

scrubbers is contracted to a third party entity but SRP remains the responsible party for 

truck loading and unloading operations, material transfer, storage, and disposal activities. 

Coal combustion residues include fly ash, bottom ash, and scrubber byproducts. Bottom 

ash and scrubber byproducts are handled in a wet state which minimizes the potential for 

dust emissions. 

d. History

The facility consists of three (3) coal-fired utility boilers and two oil-fired auxiliary 

boilers. The permittee receives the coal, which has an average sulfur content between 

0.5% and 0.75% by weight, from a nearby coal mine. Coal-fired boilers U1, U2, and 

U3 and oil-fired auxiliary boilers AUX-A and AUX-B commenced construction in 

1970. The construction of these boilers predated EPA's preconstruction permit 

regulations. 

Particulate emissions from boilers U1 through U3 are controlled by Electrostatic 

Precipitators (ESP). Flue Gas Desulfurization (FGD) systems for SO2 control were 

installed in 1997, 1998, and 1999 on boilers U3, U2, and U1, respectively. The 

associated limestone handling system was constructed in 1997. In 2008, the source 

received a PSD permit to install Low-NOX burners (LNBs) and Separated Over-fire Air 

(SOFA) systems on the three existing boilers. The LNB/SOFA systems were installed 

in 2009, 2010, and 2011 on boilers U3, U2, and U1, respectively. The permittee also 

plan to install mercury control systems in 2015 for boilers U1 through U1 through U3 

using powdered activated carbon (PAC) and calcium bromide.

On February 9, 2015, the permittee submitted a minor NSR permit application to both 

US EPA and NNEPA for the construction of a refined coal system as part of the coal 
Page 3 of 29

handling operation at the facility. The refined coal system will be owned and operated 

by a third-party which will be contracted out by SRP. This NSR permit application is

currently reviewed by US EPA. 

e. Existing Approvals

The source has been operating under Part 71 Operating Permit NN-ROP-05-06, issued 

on July 3, 2008, and the following approvals:

(a) PSD Permit #AZ 08-01, issued on November 20, 2008. 

(b) Title V Permit Reopening #NN-ROP-05-06-A, issued on October 28, 2011.

(c) PSD Permit Amendment #AZ 08-01A, issued on February 6, 2012; amended on 

August 26, 2015.

(d) Tribal Minor NSR Permit #T-0004-NN, issued on August 26, 2015

f. Proposed Modifications to the Part 71 Permit:

The permittee requested the following changes made to their Part 71 permit:

(1) Changes to the maximum heat input capacity of the boilers:

The maximum heat input capacity for each of the boilers U1, U2, and U3 has 

been reduced from 7,725 MMBtu/hr to 7,410 MMBtu/hr. This change was 

requested by the permittee because the heating value of coal received at this 

plant has decreased in recent years and the revised heat input of 7,410 

MMBtu/hr for each boiler better reflects the estimated maximum boiler 

capacity. This change will not result in increases of emissions from these units 

and is considered a minor permit modification. 

(2) Revise the insignificant activities listed:

The list of insignificant activities and emissions in Section 1.j of this Statement 

of Basis has been updated based on information submitted by the permittee on 

July 24, 2014. The new emergency fire pump (NGS-120A) is subject to the 

New Source Performance Standards (NSPS) for Stationary Compression 

Ignition Internal Combustion Engines (40 CFR Part 60, Subpart IIII) and the 

applicable requirements of this NSPS will be included in this Part 71 permit. 

These changes are considered a significant permit modification.

(3) Update the unit description for coal hopper feeders (L1-L12):

The permittee installed a wet dust suppression system (Mee Fog System) to 

control the twelve (12) coal hopper feeders (L1-L12) in 2007. This information 

was not include in the permit application for the previous Part 71 permit, issued 

on January 4, 2008. However, the installation of this control equipment 
Page 4 of 29

decreases the particulate emissions from these units and is considered a minor 

permit modification.

(4) Add operating limits for auxiliary boilers AUX A and AUX B:

In order to be qualify for “limited-use” units under 40 CFR Part 63, Subpart 

DDDDD (National Emission Standards for Hazardous Air Pollutants for 

Industrial, Commercial, and Institutional Boilers and Process Heaters), the 

permittee requested to include an operating limit of 10% of the annual capacity 

into this Part 71 renewal permit for the auxiliary boilers. This Part 71 permit 

will also include additional recordkeeping requirements for these auxiliary 

boilers. These proposed changes are considered significant permit 

modifications.

(5) Installation of PM CEMS with Boilers U1, U2, U3:

In an addendum to Title V renewal application received on January 21, 2015, 

the permittee stated that they plan to comply with the new PM emission limit in 

National Emission Standards for Hazardous Air Pollutants: Coal- and Oil-Fired 

Electric Utility Steam Generating Units (NESHAP, Subpart UUUUU) using PM 

Continuous Emission Monitoring Systems (CEMS). The PM CEMS have been 

installed for each of the boilers U1, U2, U3. Since the PM emission limit in this 

NESHAP, Subpart UUUUU is most stringent applicable PM emission limit for 

boilers U1, U2, and U3, operating PM CEMS according to the NESHAP 

requirements exempts the permittee from Continuous Assurance Monitoring 

(CAM) requirements (40 CFR Part 64) and the existing CAM requirements for 

boilers U1, U2, and U3 in the Part 71 permit could be removed. However, in an 

addendum to Title V renewal application received on March 31, 2015, the

permittee stated that PM CEMS are still not operating properly and requested 

the existing CAM requirements stayed in the Part 71 renewal permit until such 

time the PM CEMS are fully in operation. Incorporating the PM CEM 

requirements to the Part 71 permit is considered a significant permit 

modification. 

The procedure for reviewing this Part 71 renewal permit fulfills the minor permit 

modification requirements specified in 40 CFR § 71.7(e)(1) and NNOPR § 405(D), and 

the significant permit modification requirements specified in 40 CFR § 71.7(e)(3) and 

NNOPR § 405(E).

g. Permitted Emission Units and Control Equipment 

Unit ID/

Stack ID

Unit Description Maximum 

Capacity

Commenced 

Construction 

Date

Control Method

U1/

Stack S1

One (1) pulverized coal-fired boiler,

using No. 2 fuel oil for ignition fuel. Stack S1 is 

equipped with SO2, NOX, CO, and PM CEMS 

and a COMS.

7,410 MBtu/hr;

750 Net MW 1970

ESP1; FGD system 

SCBR1 (1999); 

LNB/SOFA*(2011);

Sorbent Injection (2015)
Page 5 of 29

Unit ID/

Stack ID

Unit Description Maximum 

Capacity

Commenced 

Construction 

Date

Control Method

U2/

Stack S2

One (1) pulverized coal-fired boiler,

using No. 2 fuel oil for ignition fuel. Stack S1 is 

equipped with SO2, NOX, CO, and PM CEMS 

and a COMS.

7,410 MBtu/hr;

750 Net MW 1970

ESP2; FGD system 

SCBR2 (1998); 

LNB/SOFA*(2010); 

Sorbent Injection (2015)

\U3/

Stack S3

One (1) pulverized coal-fired boiler,

using No. 2 fuel oil for ignition fuel. Stack S1 is 

equipped with SO2, NOX, CO, and PM CEMS 

and a COMS.

7,410 MBtu/hr;

750 Net MW 1970

ESP3; FGD system 

SCBR3 (1997); 

LNB/SOFA*(2009);

Sorbent Injection (2015)

AUX A One (1) auxiliary boiler;

using No. 2 fuel oil as fuel 308 MMBtu/hr 1970 N/A

AUX B One (1) auxiliary boiler;

using No. 2 fuel oil as fuel 308 MMBtu/hr 1970 N/A

Coal Handling Operations

CT1 One (1) railcar unloading operation 10,000 tons/hr 1970 wet suppression

L1 - L12 Twelve (12) hopper feeders 2,400 tons/hr

(total) 1970 wet suppression

BC-1 through 

BC-4

Four (4) conveyors to the yard surge bin 1,800 tons/hr

(each) 1970 DC-8

BC-4A One (1) conveyor to the batch weight system 100 tons/hr 1970 DC-8

BFD-5A, 

BC-5

Two (2) reclaim conveyors 1,800 tons/hr

(each) 1970 DC-8

BC-6 One (1) conveyor to the yard surge bin 1,500 tons/hr 1970 DC-8

BC-6A through 

BC-6C Three (3) conveyors to the stacker/reclaimer 1,800 tons/hr(each) 1970 wet suppression/ enclosure

BC-7

One (1) conveyor to the emergency reclaim 

hopper 1,500 tons/hr 1970 wet suppression

YSB-1 One (1) yard surge bin 1,800 tons/hr 1970 DC-8

BC-8A, 

BC-8B Two (2) conveyors to plant surge bin 1,500 tons/hr(each) 1970 DC-8

BC-8AS, 

BC-8BS

Two (2) screens 1,500 tons/hr

(each) 1970 DC-8

PSB-1 One (1) plant surge bin 3,000 tons/hr 1970 DC-5

BC-9A,

BC-9B

Two (2) conveyors to the coal silos for boilers 

U1 and U2

1,500 tons/hr

(each) 1970 DC-5

BC-10A,

BC-10B

Two (2) conveyors to the coal silos for boiler 

U3

1,500 tons/hr

(each) 1970 DC-5

CC-1A through 

CC-9A; CC-1B 

through CC-9B

Three (3) enclosed cascading conveying systems 

to the coal storage silos for boilers U1, U2, and 

U3

1,500 tons/hr

(each) 1970 DC-1 through DC-4, DC-6, and DC-7

Silos 1A through 

1G Seven (7) storage silos for boiler U1 3,000 tons/hr(each) 1970 DC-1, DC-2, and baghouse PR-1.

Silos 2A through 

2G Seven (7) storage silos for boiler U2 3,000 tons/hr(each) 1970 DC-3, DC-4, and baghouse PR-2.

Silos 3A through 

3G Seven (7) storage silos for boiler U3 3,000 tons/hr(each) 1970 DC-6, DC-7, and baghouse PR-3.

CS Outdoor coal storage piles 3,300 tons/hr

(total) 1970 wet suppression

Limestone Handling System Associated with the FGD Systems

Unloading Bay 

A and B Two (2) truck unloading operations 38 tons/hr(each) 1997 N/A

O-LSH-HOP-A One (1) limestone unloading hopper 300 tons/hr 1997 DC-9
Page 6 of 29

Unit ID/

Stack ID

Unit Description Maximum 

Capacity

Commenced 

Construction 

Date

Control Method

O-LSH-HOP-B One (1) limestone unloading hopper 300 tons/hr 1997 DC-10

O-LSH-FDR-A One (1) conveyor 300 tons/hr 1997 DC-9

O-LSH-FDR-B One (1) conveyor 300 tons/hr 1997 DC-10

O-LSH-CNV-A One (1) conveyor 300 tons/hr 1997 DC-9

O-LSH-CNV-B One (1) conveyor 300 tons/hr 1997 DC-10

O-LSH-SILO-A 

and B Two (2) limestone storage silos 300 tons/hr(each) 1997 DC-11

O-LSP-FDR-A 

and B

Two (2) enclosed feeders to the slurry 

preparation system

36 tons/hr

(each) 1997 N/A

O-LSP-CNV-A 

and B Two (2) enclosed cleanout conveyors 5 tons/hr(each) 1997 N/A

O-LSP-MILL-A 

and B Two (2) ball mills 36 tons/hr(each) 1997 N/A

LS Limestone storage piles 600 tons/hr

(total) 1997 wet suppression

Fly Ash Handling System

Silo 1 One (1) fly ash bin for boilers U1 and U2 46 tons/hr 1970 DC-S1/2

Silo 2 One (1) fly ash bin for boiler U3 46 tons/hr 1970 DC-S3

Silo 1 and 2 

Loading

Two (2) partially enclosed fly ash truck loading 

operations

38 tons/hr

(each) 1970 DC-S1/2 and DC-S3

DWB-A through 

DWB-F

Six (6) bottom ash truck loading operations.

The bottom ash is processed in a wet form

46 tons/hr

(each) 1970 wet suppression

Soda Ash/Lime Handling Systems

SAB-1A, SAB2A, SAB-1B, 

SAB-2B

Four (4) soda ash storage bins 0.4 tons/hr 

(each) 1970 dust collector BH-6

LB-1 and LB-2 Two (2) lime storage bins 0.57 tons/hr 

(each) 1970 dust collector BH-7

Reagent Handing Systems

PAC Silo A Power active carbon (PAC) storage silo 40 tons 2015 integral baghouse

PAC Silo B PAC storage silo 40 tons 2015 integral baghouse

Fugitive-PAC Truck traffic on unpaved roads for PAC delivery 30 VMT/yr** 2015 water spray

Fugitive-CaBr2 Truck traffic on unpaved roads for Calcium 

Bromide delivery 365 VMT/yr** 2015 water spray

Miscellaneous Operations

Six (6) cooling towers 813,000 gal/min

(total) 1970 N/A

TR Fugitive emissions from unpaved roads N/A 1970 wet suppression

Note: (*) LNB/SOFA = Low-NOX burner (LNB) and Separated Overfire Air (SOFA) system.

 (**) VMT = vehicle miles traveled.

h. Unpermitted Emission Units and Control Equipment 

No unpermitted emission units were found to be operating at this source during this 

review process.
Page 7 of 29

i. New Emission Units and Control Equipment 

There is no new emission unit or control equipment proposed during this review process.

j. Insignificant Activities and Emissions

This stationary source also emits air pollutants from insignificant activities and at 

insignificant emissions levels, defined in 40 CFR § 71.5(c)(11)(ii) as emissions from an 

emissions unit with the potential to emit non-hazardous regulated air pollutants in an 

amount less than 2 tons per year or a single HAP in an amount less than 1,000 pounds

per year or the de minimis level established under CAA § 112(g), whichever is less.

These emissions come from the following insignificant activities and emissions units:

(a) Nine (9) diesel-fired emergency generators, as specified in Table 1 below:

Table 1 – Diesel-Fired Emergency Generators

Unit ID Unit Description Installation 

Date

Max. Power 

Output (hp)

Type of 

Engine*

(CI or SI)

EG1 Emergency generator for boilers U1 

and U2 1983 515 CI

EG2 Emergency generator for boiler U3 1976 280 CI

EG3 Warehouse emergency generator Before 

4/1/2006 70 CI

NPG-746 Emergency generator 2003 469 CI

NGS-120A Emergency fire pump 2010 300 CI

NPG-529 Portable generator 1987 335 CI

NPG-384 Portable generator 1977 141 CI

NPG-811 Portable generator 2007 34 CI

NPG-818 Portable generator 2007 717 CI

*Note: CI = Compression Ignition; SI = Spark Ignition

(b) Equipment used during facility-wide welding activities, identified as WL.

(c) Equipment used during abrasive blasting operations.

(d) Fuel and oil storage tanks as described in Table 2 below: 

Table 2 - Fuel and Oil Storage Tanks

Unit ID Type of Liquid 

Stored

Construction 

Date

Max. Capacity 

(gallons)

NGS-062A Diesel 1991 14,000

NGS-063A Diesel 1991 14,000

NGS-064A Gas 1991 12,000

NGS-065A Used Oil 1991 2,500

NGS-067A Used Oil 1991 550

NGS-068A 30 Wt Engine Oil 1991 550

NGS-070A 30 Wt Engine Oil 1991 550
Page 8 of 29

Unit ID Type of Liquid 

Stored

Construction 

Date

Max. Capacity 

(gallons)

NGS-071A 10 Wt Engine Oil 1991 550

NGS-072A Diesel 1991 2,000

NGS-073A Diesel 1991 10,000

NGS-074A Diesel 1991 10,000

NGS-075A Diesel 1974 5,040,000

NGS-075B Diesel 2000 172,000

NGS-076A Clean Lube Oil 1973 16,000

NGS-077A Dirty Lube Oil 1973 16,000

NGS-078A 10 Wt Engine Oil 1991 550

NGS-079A Mobile Diesel Early '70s 200

NGS-080A Mobile Diesel Early '70s 200

NGS-081A Mobile Diesel Early '70s 200

NGS-082A 30 Wt Engine Oil 1991 550

NGS-083A 10 Wt Engine Oil 1991 550

NGS-084A Mobile Diesel Early '70s 200

NGS-085A Mobile Diesel 1974 400

NGS-086A Mobile Diesel 1974 350

NGS-088A Mobile Diesel 1974 400

NGS-090A Turbine Lube Oil 1974 7,450

NGS-091A Turbine Lube Oil 1974 650

NGS-092A Turbine Lube Oil 1974 650

NGS-093A Turbine Lube Oil 1975 7,450

NGS-094A Turbine Lube Oil 1975 650

NGS-095A Turbine Lube Oil 1975 650

NGS-096A Turbine Lube Oil 1976 7,450

NGS-097A Turbine Lube Oil 1976 650

NGS-098A Turbine Lube Oil 1976 650

NGS-099A H2 Seal Oil 1975 650

NGS-100A H2 Seal Oil 1974 650

NGS-101A H2 Seal Oil 1976 650

NGS-102A Transformer Oil 1973 5,600

NGS-103A Transformer Oil 1973 5,750

NGS-104A Transformer Oil 1973 5,750

NGS-106A Diesel 1974 10,000

NGS-107A Lube Oil 1991 750

NGS-108A Diesel 1991 900

NGS-109A Diesel 1974 400

NGS-110A Lube Oil 1982 300

NGS-111A Lube Oil 1982 300

NGS-112A Lube Oil 1982 300

NGS-113A Used Diesel 2012 500

NGS-113B Used Diesel 2012 500

NGS-113C Used Diesel 2012 500

NGS-114A Diesel 2002 100

NGS-115A Diesel Unknown 200

NGS-116A Diesel 2002 100

NGS-117A Diesel 2003 500
Page 9 of 29

Unit ID Type of Liquid 

Stored

Construction 

Date

Max. Capacity 

(gallons)

NGS-118A Diesel 2003 500

NGS-119A Diesel 1991 150

NGS-120A Diesel 2010 150

NGS-121A Lube Oil N/A 550

NGS-122A Diesel 2003 500

NGS-123A Diesel 2002 140

NGS-124A Diesel N/A 100

NGS-125A Diesel Unknown 200

NGS-126A Variouse Oils 2008 12 tanks, 

\60 gal each

NGS-127A Diesel/Unleaded Fuel 2005 550/100

NGS-128A Diesel/Unleaded Fuel 2005 550/100

NGS-129A Diesel Unknown 200

NGS-130A Diesel 2002 100

NGS-131 Used Oil for Heating N/A 550

NGS-131A 

through 131O Used Oil 1991 540 (each)

NGS-132A Diesel 2002 100

NGS-133A Diesel 2002 100

NGS-134A 

through 134D Used Oil N/A 250 (each)

NGS-135 Used Oil N/A 100

(e) Landscaping, building maintenance, or janitorial activities.

(f) Hand-held or manually operated equipment used for buffing, polishing, 

carving, cutting, drilling, machining, routing, sanding, sawing, surface 

grinding, or tuning of precision parts, metals, plastics, masonry, glass, or 

wood.

(g) Equipment used during powder coating operations.

(h) Lab equipment used exclusively for chemical and physical analyses.

(i) Equipment used during maintenance painting and surface coating.

(j) Equipment used during parts cleaning.

(k) Equipment used during maintenance sand blasting.

(l) Other emissions units with the potential to emit insignificant levels of 

regulated air pollutants or HAPs, as described in Table 3 below:
Page 10 of 29

Table 3 - Other Emissions Units with Insignificant Emissions Levels

Unit Description Max. Capacity 

(gallons) Number of Units

Main turbine lube oil reservoir 7,450 3

M T lube oil filter canisters 100 6

Aux turbine lube oil reservoir 650 2

Electro hydraulic control reservoir 400 3

Pulverizer lube oil reservoir 100 7

Pulverizer lube oil reservoir 300 14

Condensate pump reservoir 85 9

Boiler Feed BP oil reservoir 22 9

Inst / service air compressor 50 9

Soot blowing air compressor 250 3

Primary air fan 85 6

Induced draft fan 110 12

Forced draft fan 10 6

Coal belt gear case 35 35

Cooling tower circ pump 10 6

Cooling fan gear case 34 30

Brine concentrator compressor 100 1

Brine concentrator compressor 150 2

Chrystallizer compressor 275 1

Transformer (spare) (mineral oil) 265 2

Emergency diesel fire pump 250 1

Transformer (main) 9,550 12

Transformer (aux) 6,672 3

Transformer (main station service) 21,980 1

Transformer (main station service) 17,730 1

Reactor tank 5,500 12

Reactor tank 6,142 12

Thyrite varister oil tank 2,446 12

Large capacitor oil tanks 3.2 5,581

Small capacitor oil tanks 2.8 2,210

Transformer (50 KV at RR) 4,180 3

Circuit breaker oil tank (230 KV) 2,575 5

Transformer 4,160 V 1,409 14

Transformer 4,160 V 1,193 2

Transformer 480 V 268 28

Transformer 480 V 338 30

Transformer 480 V 343 5

Transformer/rectifier set 165 80

Transformer/rectifier set 140 32

Transformer/rectifier set 132 64

Transformer/rectifier set 117 64

Transformer 4,160 V (lake pump) 1,259 3

Transformer 480 V (lake pump) 160 2

Waste oil storage tank (cent yard) 500 1

Generator, diesel (Generac) 265 1

Recycle slurry system gear box 16 12
Page 11 of 29

Unit Description Max. Capacity 

(gallons) Number of Units

Recycle slurry system gear box 22 12

Oxidation air system oil res. 60 9

Recycle valve Hydraulic sys. 120 3

Reactivator agitator 13 30

Limestone feed tank agitator 24 3

Absorber sump agitator 0.75 6

Ball mill gear box 52 2

Ball mill lube reservoir tank 110 2

Limestone conveyor gear box 39 3

Limestone transfer tank agitator 44 1

Filtrate raw water tank gear box 44 1

Ball mill sump tank agitator 7 2

LSP sump agitator 0.75 3

Filtrate transfer tank agitator 24 1

Secondary vacuum pump gear box 4.5 3

Absorber holding tank agitator 23 10

Bi-product sump agitator 1.5 2

Primary dewatering agitator 2 6

Conveyer feedbelt gear box 1.5 2

Antifreeze storage tank (NGS-069A) 550 1

Waste antifreeze storage tank (NGS-066A) 1,000 1

Sulfuric acid tank (NGS-201) 20,000 1

Sulfuric acid tank (NGS-202, 203, and 204) 15,000 3

Sulfuric acid tank (NGS-205) 10,000 1

Ammonia tank (NGS-208) 10,000 1

Ferric chloride tank (NGS-209) 16,000 1

Acid or caustic tank (NGS-210 and 211) 24,000 2

Sodium hydroxide tank (NGS-206 and 207) 10,000 2

Sodium hypochlorite tank (NGS-212, 213, and 

214) 4,500 3

Scale inhibiter tank (NGS-215 through 220) 2,000 6

Dust Suppressant (Dusbloc) Tank 1,000 1

Dust Suppressant (Dusbloc) Tank 4,000 1

k. Enforcement Issue

There are no enforcement actions pending.

l. Emission Calculations

See Appendix A of this document for detailed calculations (pages 1 through 16). 

m. Potential to Emit

Potential to emit (PTE) means the maximum capacity to emit any CAA-regulated air 

pollutant under the facility’s physical and operational design. Any physical or 
Page 12 of 29

operational limitation on the maximum capacity of this facility to emit an air pollutant, 

including air pollution control equipment and restrictions on hours of operation or on 

the type or amount of material combusted, stored, or processed, may be treated as a part 

of its design if the limitation is enforceable by US EPA or NNEPA. Actual emissions 

are typically lower than PTE.

Potential to Emit

(tons/year)

Process/facility PM PM10 PM2.5 SO2 NOx VOC CO HAPs

Boiler U1 1,947 1,097 488 3,246 7,789 75.3 4,868 22.7

Boiler U2 1,947 1,097 488 3,246 7,789 75.3 4,868 22.7

Boiler U3 1,947 1,097 488 3,246 7,789 75.3 4,868 22.7

Auxiliary 

Boilers 3.92 1.96 0.49 13.9 47.1 0.39 9.81 1.19

Coal Handling 5.91 3.41 2.51 - - - - -

Coal Piles 

(Fugitive) 5.43 2.57 0.39 - - - - -

Limestone 

Handling 4.61 2.98 2.98 - - - - -

Limestone Piles 

(Fugitive) 4.60 2.17 0.33 - - - - -

Fly Ash 

Handling 29.2 29.2 29.2 - - - - 0.01

Soda Ash/Lime 

Handling 0.26 0.26 0.26 - - - - -

Cooling Towers 19.2 19.2 19.2 - - - - -

PAC Storage 

Silos 0.90 0.90 0.90 - - - - -

Unpaved Roads 

associated with 

PAC and CaBr2 

Delivery

1.28 0.33 0.03 - - - - -

Unpaved Roads 

(Fugitive) 546 141 14.1 - - - - -

Emergency 

Generators

(Insignificant)

1.57 1.57 1.57 1.47 22.2 1.77 4.78 Negligible

Other 

Insignificant 

Activities*

15.3 15.3 15.3 - -

Less than

5.00 - Negligible

PTE of the 

Entire Source 6,481 3,513 1,550 9,752 23,437 233 14,620 69.3

Title V Major 

Source 

Thresholds

NA 100 100 100 100 100 100

10 for a 

single HAP 

and 25 for 

total HAPs

*Note: This is an estimate on the PM/PM10/PM2.5 emissions from the welding and blasting operations, and VOC/HAP emissions 

from the parts cleaning, surface coating operations, and the storage tanks.

(a) The potential to emit of PM10, PM2.5, SO2, VOC, CO and NOx are equal to or 

greater than 100 tons per year. In addition, the potential to emit of HAPs from 
Page 13 of 29

this source is greater than 10 tons per year of a single HAP and greater than 25 

tons per year of total HAPs. Therefore, this source is considered a major source 

under 40 CFR § 71.2 (defining “major source” for purposes of the Federal 

Operating Permit Program).

(b) This source is located in an attainment area and is in one of the 28 source 

categories listed in 40 CFR § 52.21(b)(1)(i)(a). The potential to emit PM and 

all relevant criteria pollutants of this source is greater than 100 tons per year. 

Therefore, this source is an existing major source under the Prevention of 

Significant Deterioration (PSD) program. 

n. Actual Emissions 

The following table shows the actual emissions from the source. This information 

reflects the 2012 emission inventory data submitted by the permittee to NNEPA and 

the greenhouse gas (GHG) information reported to U.S. EPA under the GHG 

reporting program (40 CFR Part 98).

Pollutant Actual Emissions (tons/year)

PM10 432

SO2 4,404

VOC 200

NOx 16,276

Hydrogen Chloride 6.0

Hydrogen Fluoride 9.0

Greenhouse Gas (GHG) 17,022,237

2. Tribe Information

a. General

The Navajo Nation has the largest land base of any tribe in the country, covering more 

than 27,000 square miles in three states: Arizona, Utah, and New Mexico. The Navajo 

Nation currently is home to more than 260,000 people. Industries on the Navajo Nation

include oil and natural gas production, coal and uranium mining, electric generation and 

distribution, and tourism.

b. Local air quality and attainment status

All areas of the Navajo Nation are currently designated as attainment or unclassifiable 

for all pollutants for which a National Ambient Air Quality Standard (NAAQS) has 

been established.
Page 14 of 29

3. Prevention of Significant Deterioration (PSD) Applicability

This source is in one of the 28 source categories listed in 40 CFR § 52.21(b)(1)(i)(a) and has 

potential to emit PM and all relevant criteria pollutants greater than 100 tons per year. 

Therefore, this source is considered an existing PSD major source. This source commenced 

construction in 1970 and commenced modifications in 1997 (installation of the FGD 

systems) and 2008 (installation of LBN/SOFA systems). The construction of this source 

predated the PSD applicability date of June 1, 1975. Therefore, this source was not required 

to obtain a preconstruction permit when it was constructed in 1970. The modifications in 

1997 (installation of the FGD systems) did not result in an emissions increase above the PSD 

significance thresholds in 40 CFR § 52.21. Therefore, the modification that commenced in 

1997 did not trigger PSD. 

A PSD permit was issued to this source on July 3, 2008 for the installation of LNB/SOFA 

systems for the existing three boilers U1 through U3. An amendment to this PSD permit was 

issued on February 8, 2012. According to the requirements in the amended PSD permit, the 

permittee is required to comply with the following emission limits for each of the boilers U1 

through U3:

(a) CO emissions shall not exceed the following (BACT requirements):

(1) 0.23 lb/MMBtu based on a 30-day rolling average, and

(2) 0.15 lb/MMBtu based on a 12-month rolling average.

(b) NOx emissions shall not exceed 0.24 lb/MMBtu based on a 30-day rolling average.

In addition, the permittee is required to install CO CEMS (Continuous Emissions Monitoring 

System) to demonstrate compliance with the CO emission limits specified in the PSD 

permits.

 

The above emission limits and the associated compliance monitoring, recordkeeping, and 

reporting requirements have been included in this Part 71 permit renewal.

4. Federal Rule Applicability

(a) This source is subject to the source-specific Federal Implementation Plan (FIP) for 

Navajo Generating Station, Navajo Nation (40 CFR § 49.5513) which was 

promulgated on March 5, 2010 and later amended on August 8, 2014 to incorporate 

the Regional Haze Best Available Retrofit Technology (BART) requirements. 

Pursuant to 40 CFR § 49.5513(d), the permittee shall comply with the following 

emission limits on a plant-wide basis:

 

(1) The SO2 emissions shall not exceed 1.0 lb/MMBtu averaged over any threehour period;
Page 15 of 29

(2) The PM emissions shall not exceed 0.06 lb/MMBtu as averaged from at least 

three sampling runs per stack, each at a minimum of 60 minutes in duration

and collecting a minimum sample of 30 dry standard cubic feet;

For the stacks of Units U1, U2, and U3, opacity shall not exceed 20% averaged over a 

6 minute period, excluding condensed water droplets, or 40% averaged over 6 minutes 

during absorber upset transition periods, pursuant to 40 CFR § 49.5513(d)(4).

For dust emissions associated with coal transfer and storage and other dust-generating 

activities, opacity shall not exceed 20%, as determined using 40 CFR Part 60, 

Appendix A-4, Method 9. The permittee is required to operate and maintain the 

existing dust suppression methods for controlling dust from the coal handling and 

storage facilities. A dust control plan was submitted by the permittee on June 4, 2010 

and a revised plan was received on February 2, 2015. The revised dust control plan is 

included in this Part 71 permit renewal as Attachment A.

The permittee shall also comply with the testing, monitoring, reporting, and 

recordkeeping requirements specified in 40 CFR § 49.5513(e) and (f).

This FIP was amended on August 8, 2014 to include BART requirements (effective 

October 7, 2014). Pursuant to 40 CFR § 49.5513(j)(3), total cumulative NOX

emissions from Units 1, 2, and 3, from January 1, 2009 to December 31, 2044 shall

not exceed the 2009-2044 NOX Cap (494,899 tons). Compliance with this NOx 

emission limit must be demonstrated by the operation of the existing NOX CEMS. 

The applicable operating, maintenance, recordkeeping, and reporting requirements 

for the NOx CEMS specified in the FIP have been incorporated into this Part 71 

permit.

This FIP also requires the source to select and implement one of four operating 

scenarios listed under 40 CFR § 49.5513(j)(3)(i) to ensure compliance with the NOX

emission cap limit. However, pursuant to 40 CFR § 49.5513(j)(4)(i), the permittee 

has until December 1, 2019 to notify U.S. EPA of its choice of operating scenario. 

Therefore, the requirements associated with these four operating scenarios are not 

included in this Part 71 permit. Pursuant to 40 CFR § 49.5513(j)(4)(iii), the source is 

required to submit a permit revision application no later than December 31, 2020 to 

incorporate the specific requirements, including compliance monitoring, 

recordkeeping, and reporting requirements, associated with the selected operating 

scenario.

(b) The existing boilers U1 through U3 are considered utility units under the definition of 

40 CFR § 72.2. Therefore, these boilers are subject to the Acid Rain Program 

requirements (40 CFR Part 72 through 40 CFR Part 78), pursuant to 40 CFR §

72.6(a)(3). An Acid Rain Renewal Application was received on June 19, 2013 and the 

renewal of the acid rain permit will be issued with this Part 71 permit renewal. 

Pursuant to 40 CFR § 72.9, the permittee shall comply with the following:
Page 16 of 29

(1) The SO2 and NOX continuous emission monitoring requirements in 40 CFR 

Part 75.

(2) Acid rain emissions limitations for sulfur dioxide in 40 CFR Part 73. Pursuant 

to 40 CFR § 73.10(b) and the allowance allocations provided on October 30, 

2000, the phase II SO2 allowance allocations for the boilers at this source are 

listed in the table below:

Emission 

Unit

SO2 Allowance for years 

2010 and beyond (tons/yr)

Boiler U1 24,949 

Boiler U2 23,354

Boiler U3 23,693

Facility Total 71,996

Beginning in 2007, the SO2 allowance allocations apply to the entire facility, 

instead of each individual emission unit at this facility. 

(3) Acid rain emissions limitations for nitrogen oxides in 40 CFR Part 76 for coalfired boilers. Beginning in calendar year 2008, the permittee shall comply with 

the NOx emission limit of 0.40 lbs/MMBtu for each of the boilers U1, U2, and 

U3, pursuant to 40 CFR § 76.7(a)(1).

(c) 40 CFR § 52.145(d) (Visibility Protection) includes the following specific 

requirements for the three (3) coal-fired boilers at Navajo Generating Station: (1)

Pursuant to 40 CFR § 52.145(d)(2), the SO2 emissions from each of the coal fired 

boilers (boilers U1, U2, and U3) shall not exceed 42 ng/J (0.1 lbs/MMBtu) heat input; 

and (2) Pursuant to 40 CFR § 52.145(d)(3), compliance with the emission limit shall 

be determined daily on a plant-wide rolling annual basis.

(d) This source is subject to the Regional Haze Rule (40 CFR § 51.308) because it is a 

BART-eligible source (that is, a fossil-fuel fired steam electric plant of more than 250 

MMBtu/hr heat input which was not in operation prior to August 7, 1962, was in 

existence on August 7, 1977, and has the potential to emit greater than 250 tons per 

year of any air pollutant, see 40 CFR § 51.301) that may reasonably be anticipated to 

cause or contribute to any impairment of visibility in a mandatory Class I area.

Pursuant to 40 CFR § 51.308(e), States are required to submit implementation plans 

that, among other measures, contain either emission limits representing Best Available 

Retrofit Technology (BART) for BART-eligible sources that may reasonably be 

anticipated to cause or contribute to any impairment of visibility in any mandatory 

Class I area, or alternative measures that provide for greater reasonable progress than 

BART. Under the Clean Air Act, 42 USC § 7601(d), and the Tribal Authority Rule, 40 

CFR § 49.11(a), EPA may promulgate a federal implementation plan in the absence of 

a tribal implementation plan. Under this authority, EPA promulgated a source-specific
Page 17 of 29

FIP containing BART requirements for this source; the FIP is codified at 40 CFR §

49.5513(j).

(e) The Clean Air Mercury Rule (CAMR, CAA § 112(n)) was promulgated on May 18, 

2005 and was developed to permanently cap and reduce the mercury (Hg) emissions 

from coal-fired power plants. However, on February 8, 2008, the U.S. Court of 

Appeals for the District of Columbia Circuit issued a decision that vacated the Clean 

Air Mercury Rule. See New Jersey v. EPA, 517 F.3d 574 (D.C. Cir. 2008). Therefore, 

CAMR requirements are not included in this Part 71 permit renewal. However, 

mercury emissions from utility power plants are regulated under 40 CFR Part 63, 

Subpart UUUUU (see below for discussion of applicable 40 CFR Part 63, Subpart 

UUUUU requirements).

(f) This existing source is a major source for HAPs. The three boilers at this source (U1 

through U3) are considered existing coal-fired electric generating units (EGUs) and 

are subject to National Emission Standards for Hazardous Air Pollutants: Coal- and 

Oil-Fired Electric Utility Steam Generating Units (40 CFR Part 63, Subpart UUUUU), 

which were promulgated on February 16, 2012 and later revised on November 19, 

2014. 

Pursuant to 40 CFR § 63.9984(b), facilities subject to subpart UUUUU must comply 

with the requirements of this NESHAP by April 16, 2015, unless they receive approval 

for an extension to the compliance date under 40 CFR § 63.6(i). The permittee 

requested an extension on the compliance date for the mercury provisions of this 

NESHAP due to the technical difficulties associated with installing add-on mercury 

controls. This extension request was granted by U.S. EPA and NNEPA on January 27, 

2014. The extended compliance date for the mercury provisions is April 16, 2016. The 

source must also comply with the following implementation schedule included in the 

extension approval letter: 

(1) By April 1, 2015, submit to NNEPA a title V permit modification application 

that incorporates the final mercury control strategy. [Note: This permit 

modification application was received on March 31, 2015]

(2) By October 1, 2015, commence construction to incorporate the mercury 

control strategy on-site.

(3) By April 16, 2016, complete on-site construction and comply with all mercury 

provisions of this NESHAP.

The permitee is also required to submit interim progress reports and a final report to 

NNEPA and U.S. EPA.

The permittee shall comply with the following emission limits, pursuant to 40 CFR §

63.9991(a) and Table 2 of this NESHAP:
Page 18 of 29

(1) By April 16, 2015, filterable PM emissions shall not exceed 0.03 lb/MMBtu or 

0.3 lb/MWh.

(2) By April 16, 2015, SO2 emissions shall not exceed 0.2 lb/MMBtu or 1.5

lb/MWh.

(3) By April 16, 2016, Mercury (Hg) emissions shall not exceed 1.2 lb/TBtu or 

0.013 lb/GWh.

The permitttee plans to use a combination of calcium bromide application and 

powdered active carbon (PAC) injection system to control the Hg emissions from the 

existing coal-fired boilers. Implementation of these control technologies will require 

the installation of calcium bromide and PAC storage and handling equipment. The 

construction and operation of this Hg control system is permitted under Tribal Minor 

NSR Permit #T-0004-NN, issued on August 26, 2015.

In the permit application submitted on March 31, 2015, the permittee stated that they 

will demonstrate compliance with the SO2 emission limit in this NESHAP using 

CEMS and demonstrate compliance with the Hg emission limit using sorbent trap 

monitoring system for each stack. The permittee plans to use PM CEMS to show 

compliance with the filterable PM emissions limit under this NESHAP. However, the 

newly installed PM CEMS are not currently working properly. The permittee 

requested to conduct quarterly PM performance stack testing to show compliance with 

the PM emission limit until such time the PM CEMS operate properly, which is 

expected to occur in late 2015. 

The associated compliance, monitoring, testing, notification, recordkeeping, and 

reporting requirements are included in the permit as Attachment C. Please note that the 

requirements pertaining to Hg emissions are not applicable until April 16, 2016.

(g) Each of the boilers at this source (U1 through U3, AUXA, and AUXB) has a 

maximum heat input greater than 250 MMBtu/hr. However, these boilers commenced 

construction before August 17, 1971 and the permittee stated that no modification or 

reconstruction to the boilers has occured since the construction of these boilers. 

Therefore, the New Source Performance Standards (NSPS) for Fossil-Fuel-Fired 

Steam Generators (40 CFR Part 60, Subpart D), which apply to generators that 

commenced construction or modification after August 17, 1971, are not applicable to 

the boilers at this source. 

(h) This existing source is a major source for HAPs. Boilers U1 throught U3 are subject 

to NESHAP for Coal- and Oil-Fired Electric Utility Steam Generating Units (40 CFR 

Part 63, Subpart UUUUU). Therefore, these three boilers are not subject to the 

National Emission Standards for Hazardous Air Pollutants for Industrial, 

Commercial, and Institutional Boilers and Process Heaters (40 CFR Part 63, Subpart 

DDDDD), pursuant to 40 CFR § 63.7491(a). However, the No. 2 fuel oil-fired 

auxiliary boilers (AUX A and AUX B) are subject to this NESHAP. According to the 
Page 19 of 29

initial notification submitted by the permittee on May 30, 2013, the auxiliary boilers 

operate less than 10% of the annual capacity and are considered “limited-use” units, 

as defined in 40 CFR § 63.7575.

Pursuant to 40 CFR § 63.7500(c), limited-use boilers are only required to complete a 

tune-up every 5 years. There are no specific emission limits, energy assessment, or 

operating limits for these type of boilers. Pursuant to 40 CFR § 63.7495(b), the 

compliance date for the existing affected units is January 31, 2016. 

In addition, 40 CFR § 63.7555(d)(3) requires the permitting authority to include a 

federally enforceable condition in the permittee’s Part 71 permit to limit the operation 

of the auxiliar boilers (AUX A and AUX B) to not more than 10% of the annual 

capacity for each unit, in order to ensure they continue to qualify for “limited-use”

unit status. The permittee has requested the inclusion of this opertating limit in the 

Part 71 renewal permit.

(i) The coal handling operations at this source process more than 200 tons of coal per 

day. However, all of the coal handling operations at this source commenced 

construction before October 24, 1974 and the permittee stated that no modification to 

the coal handling operations has occured since the construction of these units. 

Therefore, pursuant to 40 CFR § 60.250, the requirements of the New Source 

Performance Standards for Coal Preparation and Processing Plants (40 CFR Part 60, 

Subpart Y) are not applicable. 

(j) Lime is considered a nonmetallic mineral as defined in 40 CFR § 60.671. The 

limestone handling system at this source commenced construction after August 31, 

1983 and performs grinding operations. Therefore, pursuant to 40 CFR § 60.670, the 

limestone handling system at this source is subject to the requirements of the New 

Source Performance Standards (NSPS) for Nonmetallic Mineral Processing Plants 

(40 CFR Part 60, Subpart OOO). The affected facilities include each grinding mill, 

screening operation, belt conveyor, storage bin, and enclosed truck loading station

associated with the limestone handling system.

Pursuant to 40 CFR § 60.672, the permittee shall comply with the following emission 

limitations:

(1) Emissions from any stack shall not exceed a PM limit of 0.05 g/dscm (0.022 

gr/dscf) and an opacity limit of 7%. 

(2) Fugitive emissions shall not exceed 10% opacity, except for crushers at which 

a capture system is not used.

(3) Fugitive emissions from crushers at which a capture system is not used shall 

not exceed 15% opacity.
Page 20 of 29

(4) Truck dumping of nonmetallic minerals into any screening operation, feed 

hopper, or crusher is exempt from the requirements of 40 CFR § 60.672.

(5) If an affected facility is enclosed in a building, then each enclosed affected 

facility must comply with the emission limits specified above, or the building 

enclosing any affected facility shall not emit any fugitive emissions exceeding 

7% opacity or any emissions from a vent exceeding a PM limit of 0.05 g/dscm 

(0.022 gr/dscf).

(6) Stack emissions from any baghouse that controls emissions from only an 

individual, enclosed storage bin shall not exceed 7 percent opacity.

The permittee shall also comply with the testing requirements in 40 CFR § 60.675 

and the recordkeeping and reporting requirements in 40 CFR § 60.676.

(k) The emergency fire pump (NGS-120A) was manufactured as a certified National Fire 

Protection Association (NFPA) fire pump engine after July 1, 2006. Therefore, this 

unit is subject to the requirements of the New Source Performance Standards for 

Stationary Compression Ignition Internal Combustion Engines (40 CFR Part 60, 

Subpart IIII), pursuant to 40 CFR § 60.4200(a)(2)(ii). All other emergency generators 

at this facility are not subject to these NSPS because they were either installed before 

April 1, 2006 or are not stationary units.

The emergency fire pump (NGS-120A) has a maximum capacity of 300 hp and was 

manufactured in 2010. The emissions from this unit shall comply with the following 

emission limits, pursuant to 40 CFR § 60.4205(c) and Table 4 of these NSPS:

(1) NMHC + NOX emissions shall not exceed 4.0 g/KW-hr or 3.0 g/HP-hr.

(2) PM emissions shall not exceed 0.2 g/KW-hr or 0.15 g/HP-hr.

Engine NGS-120A has a displacement less than 9 liters per cylinder. Pursuant to 40 

CFR § 60.4207(b), the permittee must use diesel fuel that meets the requirements of 

40 CFR § 80.510(b) for nonroad diesel fuel (ultra low sulfur diesel fuel), except that 

any existing diesel fuel purchased (or otherwise obtained) prior to October 1, 2010, 

may be used until depleted.

The permittee shall comply with the operating requirements specified 40 CFR §

60.4211(a) and the engine certification requirements in 40 CFR § 60.4211(c). There 

are no initial notification requirements for this emergency fire pump, pursuant to 40 

CFR § 60.4214(b).

(l) The emergency generators and fire pumps at this source are considered stationary 

reciprocating internal combustion engines (RICE) and are subject to the NESHAP for 

Stationary Reciprocating Internal Combustion Engines (40 CFR Part 63, Subpart 
Page 21 of 29

ZZZZ). Stationary diesel generators EG1, EG2, EG3, NPG-746, and NGS-120A are 

subject to this NESHAP. All the affected units are compression ignition engines (CI).

The applicable requirements for the affected units can be divided into the following 

three categories:

(1) Units with no specific requirements:

For the existing emergency generators with capacities greater than 500 hp (EG1), the 

permittee is not required to meet the requirements of this subpart and of 40 CFR 63, 

Subpart A, pursuant to 40 CFR § 63.6590(b)(3)(iv). No initial notification is required.

(2) Units with specific requirements:

For the existing emergency generators with capacities equal to or less than 500 hp

(EG2, EG3, and NPG-746), the permittee shall comply with the following work 

practice requirements specified in Table 2c of this subpart, pursuant to 40 CFR §

63.6602:

(1) Change oil and filter every 500 hours or annually;

(2) Inspect air cleaner every 1,000 hours or annually;

(3) Inspect hoses and belts every 500 hours or annually; and

(4) Minimize the engine's time spent at idle and minimize the engine's startup 

time to a period needed for appropriate and safe loading of the engine, not to 

exceed 30 minutes, after which time the non-startup emission limitations 

apply.

The initial compliance date for units EG2, EG3, and NPG-746 is May 3, 2013, 

pursuant to 40 CFR § 63.6595(a). 

(3) Units subjected to NSPS under 40 CFR Part 60, Subpart IIII:

The emergency fire pump (NGS-120A) is an emergency unit with a maximum 

capacity less than 500 hp and is subject to the requirements of NSPS for Stationary CI 

ICE, 40 CFR Part 60, Subpart IIII. For this unit, compliance with this NESHAP is 

demonstrated by complying with the requirements specified in the NSPS for 

Stationary CI ICE, 40 CFR Part 60, Subpart IIII, pursuant to 40 CFR § 63.6590(c).

The following table summarizes the capacity, construction date, unit category type, 

and applicable requirements for each emergency generator subject to 40 CFR Part 63, 

Subpart ZZZZ: 
Page 22 of 29

Unit ID Max. Capacity

(hp) Construction Date Unit Category Subpart ZZZZ Requirements

EG1 515 before 12/19/2002 Existing RICE None

EG2 280 before 06/12/2006 Existing RICE Work Practice

EG3 70 before 06/12/2006 Existing RICE Work Practice

NPG-746 469 before 06/12/2006 Existing RICE Work Practice

NGS-120A 300 after 06/12/2006 New RICE Compliance 

through 

compliance with 

40 CFR Part 63, 

Subpart IIII

(m) Tank NGS-064-A is used to store gasoline. However, this tank commenced 

construction in 1991. Therefore, pursuant to 40 CFR § 60.110, the New Source 

Performance Standards for Storage Vessels for Petroleum Liquids for Which 

Construction, Reconstruction, or Modification Commenced After June 11, 1973, and 

Prior to May 19, 1978 (40 CFR Part 60, Subpart K) are not applicable.

(n) Tank NGS-064-A is used to store gasoline and commenced construction in 1991. 

However, the maximum capacity of this tank is less than 40,000 gallons. Therefore, 

pursuant to 40 CFR § 60.110a, the New Source Performance Standards for Storage 

Vessels for Petroleum Liquids for Which Construction, Reconstruction, or 

Modification Commenced After May 19, 1978 and Prior to July 23, 1984 (40 CFR 

Part 60, Subpart Ka) are not applicable.

(o) The diesel storage tank NGS-075B has a maximum storage capacity greater than 75 

cubic meters (19,813 gallons) and was constructed after July 23, 1984. Since the 

diesel fuel stored in this tank has a maximum true vapor pressure of less than 3.5 kPa, 

tank NGS-075B is exempt from the requirements of the New Source Performance 

Standards for Volatile Organic Liquid Storage Vessels for Which Construction, 

Reconstruction, or Modification Commenced After July 23, 1984 (40 CFR Part 60, 

Subpart Kb), pursuant to 40 CFR § 60.110b(b). Therefore, the requirements of this 

NSPS are not applicable.

(p) The parts washers at this source do not use halogenated HAP solvents. Therefore, 

pursuant to 40 CFR § 63,460(a), these units are not subject to the requirements of the 

NESHAP for Halogenated Solvent Cleaning (40 CFR Part 63, Subpart T).

(q) There are specific SO2, NOX, and CO emission limits (in lbs/MMBtu) for boilers U1 

through U3. The FIP for this source (40 CFR § 49.5513) and the PSD Permit #AZ 08-

01, issued on November 20, 2008, require the source to install and operate CEMS to 

ensure continuous compliance with the SO2, NOX, and CO emission limits. These 

requirements have been incorporated into this part 71 renewal permit. Therefore, the

SO2, NOx, and CO emissions from boilers U1 through U3 are exempt from the 

requirements of 40 CFR Part 64 (Compliance Assurance Monitoring (CAM)), 

pursuant to 40 CFR § 64.2(b)(1)(vi).
Page 23 of 29

The FIP for this source (40 CFR § 49.5513) has specific PM emission limits for boilers 

U1 through U3 and the CAM requirements used to apply to these units. However, the 

permittee recently installed PM CEMS for each of the boilers U1, U2, and U3 to 

demonstrate compliance with the PM emission limits specified in NESHAP, Subpart 

UUUUU. Since the PM emission limit in this NESHAP is more stringent than the PM 

emission limits in FIP, compliance with the PM emission limit for NESHAP, Subpart 

UUUUU using the new PM CEMS is sufficient to demonstrate compliance with PM 

emission limit in FIP. Therefore, the PM emissions from boilers U1 through U3 are 

exempt from the CAM requirements, pursuant to 40 CFR § 64.2(b)(1)(vi). A permit 

condition (Condition II.N) has been added to this Part 71 permit renewal to require the 

operation of PM CEMS with the stacks associated with boilers U1, U2, and U3. 

However, in an addendum to Title V renewal application received on March 31, 2015,

the permittee stated that PM CEMS are still not operating properly and requested the 

existing CAM requirements stayed in the Part 71 renewal permit until such time the 

PM CEMS are fully in operation. Therefore, the CAM requirements from the current 

Part 71 permit are still included in the renewal permit. The CAM requirements 

(included as Condition II.N of the renewal permit) are summarized in the table below 

and will still apply until such time the PM CEMS operate properly:

Electrostatic 

Precipitator

Wet Limestone 

Scrubber

Wet Limestone 

Scrubber

Wet Limestone 

Scrubber

Indicator

Number of 

chambers/fields in 

service

Number of Spray 

levels in service

Wet limestone 

scrubber exhaust 

temperature

Wet limestone 

scrubber on/off

Measurement 

Approach

The number of 

chambers/fields in 

service is monitored 

and logged on a 

continuous basis.

The number of wet 

limestone scrubber 

spray levels in service 

is monitored on a 

continuous basis.

The wet 

limestone 

scrubber exhaust 

temperatures are 

monitored at the 

absorber outlets 

prior to the stack 

using a J-type 

thermocouple.

The wet limestone 

scrubber on/off 

signal is monitored 

on a continuous 

basis.

Indicator 

Threshold

An excursion is 

defined as follows: 

When an ESP unit is 

operating with more 

than 3 chambers (18 

fields) out of service 

during normal 

operation of the 

boiler.

An excursion is 

defined as follows: 

When a ESP unit is 

operating with more 

than one chamber (6 

fields) out of service 

and less than 2 spray 

levels are operating in 

the wet limestone 

scrubber associated 

with the same boiler, 

during normal 

operations of the 

boiler.

An excursion is 

defined as 

follows: When 

the wet limestone 

scrubber exhaust 

temperatures 

exceed 1450F for 

more than one 

unit, on a 1-hour 

average basis, 

during normal 

operation of the 

boilers.

An excursion is 

defined as follows: 

When the wet 

limestone scrubber 

is bypassed for 

more than one unit, 

for at least 1 hour, 

during normal 

operation of the 

boilers.
Page 24 of 29

Electrostatic 

Precipitator

Wet Limestone 

Scrubber

Wet Limestone 

Scrubber

Wet Limestone 

Scrubber

Performance 

Criteria

The monitoring system 

consists of status bits 

from the Automatic 

Voltage Controllers 

(AVCs), supplemented 

with operating logs, 

which indicate the 

number of 

chambers/fields that 

are operational.

The monitoring 

system consists of a 

signal indicating the 

number of wet 

limestone scrubber 

spray levels that are 

operational.

The monitoring 

system consists of 

a J-type 

thermocouple at 

the wet limestone 

scrubber exhaust 

with a minimum 

accuracy of ±5 

percent.

The monitoring 

system consists of 

an on/off signal 

indicating that the 

wet limestone 

scrubber is 

operational.

Verification 

of 

Operational 

Status

Not Applicable Not Applicable Not Applicable Not Applicable

QA/QC

Monitoring equipment 

will be maintained and 

operated according to 

manufacturer 

recommendations.

The wet limestone 

scrubber spray level 

signal will undergo an 

annual verification 

check.

The 

thermocouple 

will undergo a 

quarterly 

verification check 

using a standard 

temperature 

indicator.

The wet limestone 

scrubber on/off 

signal will undergo 

an annual

verification check.

Indicator 

Threshold

An excursion is 

defined as follows: 

When an ESP unit is 

operating with more 

than 3 chambers (18 

fields) out of service 

during normal 

operation of the 

boiler.

An excursion is 

defined as follows: 

When a ESP unit is 

operating with more 

than one chamber (6 

fields) out of service 

and less than 2 spray 

levels are operating in 

the wet limestone 

scrubber associated 

with the same boiler, 

during normal 

operations of the 

boiler.

An excursion is 

defined as follows: 

When the wet 

limestone scrubber 

exhaust 

temperatures 

exceed 1450F for 

more than one unit, 

on a 1-hour 

average basis, 

during normal 

operation of the 

boilers.

An excursion is 

defined as follows: 

When the wet 

limestone scrubber 

is bypassed for 

more than one 

unit, for at least 1 

hour, during 

normal operation 

of the boilers.

Monitoring 

Frequency

Continuous Continuous The wet limestone 

scrubber exhaust 

temperature is 

measured 

continuously.

The wet limestone 

scrubber on/off 

signal is monitored 

continuously.

Data 

Collection 

Procedures

The AVC status bits 

are recorded by the 

BHA WinDAC Data 

Acquisition and 

Control Software, 

and supplemented 

with operating logs.

The wet limestone 

scrubber spray level 

signal will be 

recorded on a 

continuous basis by the 

data acquisition 

handling system.

The wet limestone 

scrubber exhaust 

temperature will be 

recorded as an 

hourly average by a 

data acquisition 

handling system.

The wet limestone 

scrubber on/off 

signal will be 

recorded on a 

continuous basis 

by the data 

acquisition 

handling system.
Page 25 of 29

Electrostatic 

Precipitator

Wet Limestone 

Scrubber

Wet Limestone 

Scrubber

Wet Limestone 

Scrubber

Averaging 

Period Not Applicable Not Applicable 1-Hour average Not Applicable

There are no specific PM/PM10 emission limitations for the coal handling operations 

or the ash handling operations. Therefore, pursuant to 40 CFR § 64.2(a), the 

requirements of 40 CFR Part 64 (CAM) are not applicable to these units. 

The limestone handling operations at this source are subject to the PM emission limit 

in 40 CFR Part 60, Subpart OOO. The control devices associated with the limestone 

handling operations are baghouses DC-9, DC-10, and DC-11. The pre-control PTE of 

baghouse DC-9, DC-10, and DC-11 is each less than the major source threshold of 100 

tons/yr. Therefore, pursuant to 40 CFR § 64.2(a), these baghouses are not subject to 40 

CFR Part 64 (CAM). 

(r) The permittee is subject to the requirements of the Asbestos NESHAP (40 CFR Part 

61, Subpart M). The applicable requirements are specified in the permit document.

(s) The permittee is subject to the requirements of 40 CFR Part 82 (Protection of 

Stratospheric Ozone). The applicable requirements are specified in the permit 

document.

Summary of Applicable Federal Requirements

Federal Air Quality Requirement Current or Future 

Requirement

Federal Implementation Plan for NGS (40 CFR §

49.5513)

Current

Acid Rain Regulations (40 CFR Parts 72-78) Current

CAM Requirements (40 CFR Part 64) Current

(until PM CEMS operate properly)

Visibility FIP (40 CFR § 52.145(d)) Current

NSPS for Nonmetallic Mineral Processing Plants (40 

CFR Part 60, Subpart OOO) Current

NSPS for Stationary Compression Ignition Internal 

Combustion Engines (40 CFR Part 60, Subpart IIII) Current

NESHAP for Coal- and Oil-Fired Electric Utility 

Steam Generating Units (40 CFR Part 63, Subpart 

UUUUU)

Current

NESHAP for Industrial, Commercial, and Institutional 

Boilers and Process Heaters (40 CFR 63, Subpart 

DDDDD)

Current

NESHAP for Stationary Reciprocating Internal 

Combustion Engines (40 CFR Part 63, Subpart ZZZZ) Current

Asbestos NESHAP (40 CFR Part 61, Subpart M) Current
Page 26 of 29

Federal Air Quality Requirement Current or Future 

Requirement

Protection of Stratospheric Ozone (40 CFR Part 82) Current

Regional Haze BART Requirements (40 CFR §

51.308)

Current 

(Included in the NGS FIP)

5. Additional Requirement

(a) In order to demonstrate compliance with 40 CFR Part 60, Subpart OOO for the 

existing limestone handling system, a reopening permit was issued on November 13, 

2003 and included the following testing, monitoring, and recordkeeping requirements 

for baghouses DC-9, DC-10, and DC-11, which are used to control the emissions 

from the limestone handling system:

(1) Stack testing for particulate matter emissions from the exhaust stacks of 

baghouses DC-9, DC-10, and DC-11 shall be conducted once every five (5) 

years using EPA Method 5 or Method 17. In addition, if during any twelve 

(12) consecutive month period visible emissions are observed three times 

from any one baghouse, the permittee shall conduct a performance test on that 

baghouse within 120 days of the third observation.

(2) The permittee shall conduct a weekly visual emission survey of the exhaust 

stacks of baghouses DC-9, DC-10, and DC-11 while the equipment is 

operating and during daylight hours, by a person certified in EPA Method 9. If 

any visible emissions are observed, the permittee shall conduct an opacity test 

using EPA Method 9 within 24 hours while the equipment is operating in 

accordance with 40 CFR § 60.675. 

(3) The permittee shall record and maintain the following records for each visible 

emission observation or Method 9 opacity test:

(i) the date and time of the observation and the name of the observer;

(ii) the unit ID number;

(iii) a statement of whether visible emissions were detected, and if so, 

whether they were observed continuously or intermittently; and

(iv) the results of the Method 9 test, if required.

(b) Pursuant to Tribal Minor NSR Permit #T-0004-NN, issued on August 26, 2015, the 

permittee shall comply with the following requirements for the new mercury emission 

control system (including a new powdered activated carbon (PAC) injection system 

and a new calcium bromide application system): 

(1) Vehicle miles travel (VMT) for truck traffic associated with the delivery of 
Page 27 of 29

PAC shall not exceed 30 VMT per 12-month period.

(2) VMT for truck traffic associated with the delivery of calcium bromide shall 

not exceed 365 VMT per 12-month period.

(3) The permittee shall monitor and maintain records on a calendar month basis of 

each PAC deliver, the VMT of each delivery, and determine the 12-month 

rolling total.

(4) The permittee shall monitor and maintain records on a calendar month basis of 

each calcium bromide deliver, the VMT of each delivery, and determine the 

12-month rolling total.

(5) At least once during each calendar week, the permittee shall perform a visible 

emissions survey for each PAC silo (Silos A and B). The survey shall be 

performed during daylight hours by an individual trained in EPA Method 22 

while the equipment is in operation. If visible emissions are detected during 

the survey, the permittee shall take corrective action so that within 24 hours 

no visible emissions are detected.

6. Endangered Species Act

Pursuant to Section 7 of the Endangered Species Act (ESA), 16 U.S.C. § 1536, and its 

implementing regulations at 50 CFR Part 402, USEPA is required to ensure that any action 

authorized, funded, or carried out by USEPA is not likely to jeopardize the continued existence 

of any Federally-listed endangered species or threatened species or result in the destruction or 

adverse modification of such species’ designated critical habitat. NNEPA is issuing this federal 

Part 71 permit pursuant to a delegation from USEPA. However, this permit does not authorize 

the construction of new emission units or emission increases from existing units, nor does it 

otherwise authorize any other physical modifications to the facility or its operations. Therefore, 

NNEPA and USEPA have concluded that the issuance of this permit will have no effect on listed 

species or their critical habitat.

7. Use of All Credible Evidence

Determinations of deviations from, continuous or intermittent compliance with, or violations of 

the permit are not limited to the testing or monitoring methods required by the underlying 

regulations or this permit; other credible evidence (including any evidence admissible under the 

Federal Rules of Evidence) must be considered by the source, NNEPA, and U.S. EPA in such 

determinations.

8. NNEPA Authority

Authority to administer the Part 71 Permit Program was delegated to the Navajo Nation EPA 

by USEPA Region IX in part on October 13, 2004 and in whole on March 21, 2006. This 

permit is issued pursuant to the May 2005 Voluntary Compliance Agreement between the 
Page 28 of 29

permittee and the Navajo Nation, which provided for Navajo regulation of NGS for CAA 

purposes. The permittee shall comply with the terms of this permit and shall be subject to 

enforcement of the permit by the Navajo Nation EPA and USEPA, pursuant to the terms of the 

Voluntary Compliance Agreement. The permittee’s agreement to comply is effective upon the 

permittee’s written acceptance of the permit and expires at the end of the permit term, unless 

the permit is renewed. The permittee’s agreement to comply may be withdrawn during the 

permit term only if the Voluntary Compliance Agreement is terminated or expires as provided 

in that Agreement.

9. Public Participation

a. Public Notice

As required by NNOPR § 403(A), this permit renewal is being publicly noticed and 

made available for public comment. The content, methods, and timing of public notice 

are described in NNOPR § 403(B)-(D), and include a 30- day public comment period. 

See also 40 CFR § 71.11(d) (equivalent public notice and comment provisions).

Public notice of this proposed permit action will be provided by mailing a copy of the 

notice to the permittee, U.S. EPA Region 9, and the affected states (Utah and Arizona). 

A copy of the notice will also be provided to all persons who submit a written request 

to be included on the mailing list to the following individual:

Tennille Begay

Navajo Nation Operating Permit Program

P.O. Box 529

Fort Defiance, AZ 86504

E-mail: tbbegay@navajo-nsn.gov

Public notice will be published in a daily or weekly newspaper of general circulation in 

the area affected by this source.

b. Opportunity for Comment

Members of the public may review a copy of the draft permit prepared by NNEPA, this 

statement of basis for the draft permit, the application, and all supporting materials 

submitted by the source at:

Navajo Nation Air Quality Control Program

Route 112 North, Bldg No. F004-51

Fort Defiance, AZ 86504

Copies of the draft permit and this statement of basis can also be obtained free of 

charge from NNEPA’s website:
Page 29 of 29

www.navajonationepa.org/airqty/permits

or by contacting Tennille Begay at the NNAQCP address listed above or by telephone 

at (928) 729-4248. All documents will be available for review at the NNAQCP office 

indicated above during regular business hours.

If you have comments on the draft permit, you must submit them during the 30-day 

public comment period. All comments received during the public comment period and 

all comments made at any public hearing will be considered in arriving at a final 

decision on the permit. The final permit is a public record that can be obtained by 

request. A statement of reasons for any changes made to the draft permit and responses 

to comments received will be sent to persons who commented on the draft permit.

If you believe that any condition of the draft permit is inappropriate, you must raise all 

reasonably ascertainable issues and submit all arguments supporting your position by 

the end of the comment period. Any supporting documents must be included in full and 

may not be incorporated by reference, unless they are already part of the administrative 

record for this permit or consist of tribal, state or federal statutes or regulations or other 

generally available referenced materials.

Any comments on the acid rain permit shall be submitted to US EPA at the following 

address:

EPA Region 9

75 Hawthorne Street

San Francisco, CA 94105

E-mail: R9AirPermits@epa.gov

c. Opportunity to Request a Hearing

A person may submit a written request for a public hearing to Tennille Begay, at the 

address listed in Section 9(a) above, by stating the nature of the issues to be raised at 

the public hearing. Based on the number of hearing requests received, NNEPA will 

hold a public hearing whenever it finds there is a significant degree of public interest in 

a draft operating permit. If a public hearing is held, NNEPA will provide public notice 

of the hearing and any person may submit oral or written statements and data 

concerning the draft permit.

d. Mailing List

If you would like to be added to NNEPA’s mailing list to be informed of future actions 

on this or other Clean Air Act permits issued on the Navajo Nation, please send your 

name and address to Tennille Begay at the address listed in Section 9(a) above.
Page 1 of 16 SOB App A

Appendix A: Emission Calculations

Criteria Pollutant Emissions from 

the Coal Fired Boiler U1

Company Name: Navajo Generating Station

Address: 5 miles east of Page, off U.S. Highway 98, Page, AZ 86040

Permit No.: NN-OP-15-06

Reviewer: ERG/YC

Date: September 4, 2015

Max. Heat Input Capacity

Ash Content (A)

13.5 % (provided by the source)

PMa PM10b PM2.5b SO2

c NOXd VOCe COd

 Emission Factor 0.06 0.729 0.324 0.10 0.24 0.05 0.15

(0.054A) (0.024A)

(lbs/MMBtu) (lbs/ton) (lbs/ton) (lbs/MMBtu) (lbs/MMBtu) (lbs/ton) (lbs/MMBtu)

Potential to Emit in (tons/yr) 1,947 1,097 488 3,246 7,789 75.3 4,868

a

 PM emission factor is the emission limit in 40 CFR 49.5513(d)(2). 

b

 PM10 and PM2.5 emission factors are from AP-42, Table 1.1-6 (09/98) for ESP control. 

c

 The SO2 emission factor is based on the emission limit in 40 CFR 52.145(d).

d

 The NOX and CO emission factors are based on the emission limits in the PSD Permit AZ 08-01A, issued on 2/8/12.

e

 VOC emission factor is from AP-42, Tables 1.1-19 (09/98).

The heating value of the coal used at this plant is 21.562 MMBtu/ton, provided by the source.

Methodology

PTE of PM10, PM2.5, and VOC (tons/yr) = Max. Heat Input (MMBtu/hr) / 21.562 MMBtu/ton x Emission Factor (lbs/ton) x 8760 hrs/yr x 1 ton/2,000 lbs

PTE of PM, SO2, NOx and CO (tons/yr) = Max. Heat Input (MMBtu/hr) x Emission Factor (lbs/MMBtu) x 8760 hr/yr x 1 ton/2,000 lbs

Pollutant

MMBtu/hr

7,410
Page 2 of 16 SOB App A

Appendix A: Emission Calculations

Criteria Pollutant Emissions from 

the Coal Fired Boiler U2

Company Name: Navajo Generating Station

Address: 5 miles east of Page, off U.S. Highway 98, Page, AZ 86040

Permit No.: NN-OP-15-06

Reviewer: ERG/YC

Date: September 4, 2015

Max. Heat Input Capacity

Ash Content (A)

13.5 % (provided by the source)

PMa PM10b PM2.5b SO2

c NOXd VOCe COd

 Emission Factor 0.06 0.729 0.324 0.10 0.24 0.05 0.15

(0.054A) (0.024A)

(lbs/MMBtu) (lbs/ton) (lbs/ton) (lbs/MMBtu) (lbs/MMBtu) (lbs/ton) (lbs/MMBtu)

Potential to Emit in (tons/yr) 1,947 1,097 488 3,246 7,789 75.3 4,868

a

 PM emission factor is the emission limit in 40 CFR 49.5513(d)(2). 

b

 PM10 and PM2.5 emission factors are from AP-42, Table 1.1-6 (09/98) for ESP control. 

c

 The SO2 emission factor is based on the emission limit in 40 CFR 52.145(d).

d

 The NOX and CO emission factors are based on the emission limits in the PSD Permit AZ 08-01A, issued on 2/8/12.

e

 VOC emission factor is from AP-42, Tables 1.1-19 (09/98).

The heating value of the coal used at this plant is 21.562 MMBtu/ton, provided by the source.

Methodology

PTE of PM10, PM2.5, and VOC (tons/yr) = Max. Heat Input (MMBtu/hr) / 21.562 MMBtu/ton x Emission Factor (lbs/ton) x 8760 hrs/yr x 1 ton/2,000 lbs

PTE of PM, SO2, NOx and CO (tons/yr) = Max. Heat Input (MMBtu/hr) x Emission Factor (lbs/MMBtu) x 8760 hr/yr x 1 ton/2,000 lbs

Pollutant

MMBtu/hr

7,410
Page 3 of 16 SOB App A

Appendix A: Emission Calculations

Criteria Pollutant Emissions from 

the Coal Fired Boiler U3

Company Name: Navajo Generating Station

Address: 5 miles east of Page, off U.S. Highway 98, Page, AZ 86040

Permit No.: NN-OP-15-06

Reviewer: ERG/YC

Date: September 4, 2015

Max. Heat Input Capacity

Ash Content (A)

13.5 % (provided by the source)

PMa PM10b PM2.5b SO2

c NOXd VOCe COd

 Emission Factor 0.06 0.729 0.324 0.10 0.24 0.05 0.15

(0.054A) (0.024A)

(lbs/MMBtu) (lbs/ton) (lbs/ton) (lbs/MMBtu) (lbs/MMBtu) (lbs/ton) (lbs/MMBtu)

Potential to Emit in (tons/yr) 1,947 1,097 488 3,246 7,789 75.3 4,868

a

 PM emission factor is the emission limit in 40 CFR 49.5513(d)(2). 

b

 PM10 and PM2.5 emission factors are from AP-42, Table 1.1-6 (09/98) for ESP control. 

c

 The SO2 emission factor is based on the emission limit in 40 CFR 52.145(d).

d

 The NOX and CO emission factors are based on the emission limits in the PSD Permit AZ 08-01A, issued on 2/8/12.

e

 VOC emission factor is from AP-42, Tables 1.1-19 (09/98).

The heating value of the coal used at this plant is 21.562 MMBtu/ton, provided by the source.

Methodology

PTE of PM10, PM2.5, and VOC (tons/yr) = Max. Heat Input (MMBtu/hr) / 21.562 MMBtu/ton x Emission Factor (lbs/ton) x 8760 hrs/yr x 1 ton/2,000 lbs

PTE of PM, SO2, NOx and CO (tons/yr) = Max. Heat Input (MMBtu/hr) x Emission Factor (lbs/MMBtu) x 8760 hr/yr x 1 ton/2,000 lbs

Pollutant

MMBtu/hr

7,410
Page 4 of 16 SOB APP A

Appendix A: Emission Calculations

 HAP Emissions

From the Coal Fired Boilers U1 through U3

Company Name: Navajo Generating Station

Address: 5 miles east of Page, off U.S. Highway 98, Page, AZ 86040

Permit No.: NN-OP-15-06

Reviewer: ERG/YC

Date: September 4, 2015

Emission Unit: Boiler U1 Boiler U2 Boiler U3

Max. Heat Input Capacity (MMBtu/hr): 7,410 7,410 7,410

Pollutant Emission Factor Unit PTE of HAP for B1 

(tons/yr)

PTE of HAP for B2 

(tons/yr)

PTE of HAP for B3 

(tons/yr)

Total PCDD 6.66E-10 (lbs/ton) 1.00E-06 1.00E-06 1.00E-06

Total PCDF 1.09E-09 (lbs/ton) 1.64E-06 1.64E-06 1.64E-06

Total PAH 2.08E-05 (lbs/ton) 0.03 0.03 0.03

Acetaldehyde 5.70E-04 (lbs/ton) 0.86 0.86 0.86

Acetophenone 1.50E-05 (lbs/ton) 0.02 0.02 0.02

Acrolein 2.90E-04 (lbs/ton) 0.44 0.44 0.44

Benzene 1.30E-03 (lbs/ton) 1.96 1.96 1.96

Benzyl Chloride 7.00E-04 (lbs/ton) 1.05 1.05 1.05

DEHP 7.30E-05 (lbs/ton) 0.11 0.11 0.11

Bromoform 3.90E-05 (lbs/ton) 0.06 0.06 0.06

Carbon Disulfide 1.30E-04 (lbs/ton) 0.20 0.20 0.20

2-Chloroacetophenone 7.00E-06 (lbs/ton) 0.01 0.01 0.01

Chlorobenzene 2.20E-05 (lbs/ton) 0.03 0.03 0.03

Chloroform 5.90E-05 (lbs/ton) 0.09 0.09 0.09

Cumene 5.30E-06 (lbs/ton) 0.01 0.01 0.01

Cyanide 2.50E-03 (lbs/ton) 3.76 3.76 3.76

2,4-Dinitrotoluene 2.80E-07 (lbs/ton) 0.00 0.00 0.00

Dimethyl Sulfate 4.80E-05 (lbs/ton) 0.07 0.07 0.07

Ethyl Benzene 9.40E-05 (lbs/ton) 0.14 0.14 0.14

Ethyl Chloride 4.20E-05 (lbs/ton) 0.06 0.06 0.06

Ethylene Dichloride 4.00E-05 (lbs/ton) 0.06 0.06 0.06

Ethylene Dibromide 1.20E-06 (lbs/ton) 0.00 0.00 0.00

Formaldehyde 2.40E-04 (lbs/ton) 0.36 0.36 0.36

Hexane 6.70E-05 (lbs/ton) 0.10 0.10 0.10

Isophorone 5.80E-04 (lbs/ton) 0.87 0.87 0.87

Methyl Bromide 1.60E-04 (lbs/ton) 0.24 0.24 0.24

Methyl Chloride 5.30E-04 (lbs/ton) 0.80 0.80 0.80

Methyl Hydrazine 1.70E-04 (lbs/ton) 0.26 0.26 0.26

Methyl Methacrylate 2.00E-05 (lbs/ton) 0.03 0.03 0.03

Methyl Tert Butyl Ether 3.50E-05 (lbs/ton) 0.05 0.05 0.05

Methylene Chloride 2.90E-04 (lbs/ton) 0.44 0.44 0.44

Phenol 1.60E-05 (lbs/ton) 0.02 0.02 0.02

Propionaldehyde 3.80E-04 (lbs/ton) 0.57 0.57 0.57

Tetrachloroethylene 4.30E-05 (lbs/ton) 0.06 0.06 0.06

Toluene 2.40E-04 (lbs/ton) 0.36 0.36 0.36

1,1,1-Trichloroethane 2.00E-05 (lbs/ton) 0.03 0.03 0.03

Styrene 2.50E-05 (lbs/ton) 0.04 0.04 0.04

Xylenes 3.70E-05 (lbs/ton) 0.06 0.06 0.06

Vinyl Acetate 7.60E-06 (lbs/ton) 0.01 0.01 0.01

Antimony 1.80E-05 (lbs/ton) 0.03 0.03 0.03

Arsenic 4.10E-04 (lbs/ton) 0.62 0.62 0.62

Beryllium 2.10E-05 (lbs/ton) 0.03 0.03 0.03

Cadmium 5.10E-05 (lbs/ton) 0.08 0.08 0.08

Chromium 2.60E-04 (lbs/ton) 0.39 0.39 0.39

Chromium (VI) 7.90E-05 (lbs/ton) 0.12 0.12 0.12

Cobalt 1.00E-04 (lbs/ton) 0.15 0.15 0.15

Lead 4.20E-04 (lbs/ton) 0.63 0.63 0.63

Manganese 4.90E-04 (lbs/ton) 0.74 0.74 0.74

Mercury* 1.20E-06 (lbs/MMBtu) 0.04 0.04 0.04

Nickel 2.80E-04 (lbs/ton) 0.42 0.42 0.42

Selenium 1.30E-03 (lbs/ton) 1.96 1.96 1.96

Hydrogen Fluoride* 5.30E-05 (lbs/MMBtu) 1.72 1.72 1.72

Hydrogen Chloride* 7.70E-05 (lbs/MMBtu) 2.50 2.50 2.50

Total 22.7 22.7 22.7

Note: Emission factors are from AP-42, Tables 1.1-12, 1.1-13, 1.1-14, and 1.1-18 for Coal Combustion (09/98). 

* Hg emission factor is based on the Hg emission limit in 40 CFR 63, Subpart UUUUU.

** HF and HCl emission factors are based on the stack testing results in April, 2010, provided by the source.

The heating value of the coal used at this plant is 21.562 MMBtu/ton, provided by the source.

Methodology

PTE of HAP (tons/yr) = Max. Heat Input (MMBtu/hr) / 21.6 MMBtu/ton x Emission Fator (lbs/ton) x 8760 hrs/yr x 1 ton/2000 lbs

PTE of Hg, HF, and HCl (tons/yr) = Max. Heat Input (MMBtu/hr) x Emission Factor (lbs/MMBtu) x 8760 hr/yr x 1 ton/2,000 lbs
Page 5 of 16 SOB App A

Appendix A: Emission Calculations

No. 2 Fuel Oil Combustion 

(MMBtu/hr > 100)

From Two (2) 308 MMBtu/hr Auxiliary Boilers

Company Name: Navajo Generating Station

Address: 5 miles east of Page, off U.S. Highway 98, Page, AZ 86040

Permit No.: NN-OP-15-06

Reviewer: ERG/YC

Date: September 4, 2015

Max. Fuel Usage S = Weight % Sulfur Operation Hour Limit*

(kgal/hr) (hrs/yr)

(each) 2.24 (each) 0.05 876

Pollutant

PM PM10 PM2.5 SO2 NOx VOC CO

Emission Factor in lbs/kgal 2.00 1.00 0.25 7.1 24.0 0.2 5.0

(142 S)

Potential to Emit in tons/yr for 2 units 3.92 1.96 0.49 13.9 47.1 0.39 9.81

Emission factors are from AP-42, Tables 1.3-1, 1.3-2, 1.3-3, and 1.3-6 (AP-42, 05/10).

* Pursuant to 40 CFR 63.7555(d)(3) (NESHAP, Subpart DDDDD), limited use boilers means boilers that limit the annual capacity factor to less than or equal to 10 percent

Methodology

PTE (tons/yr) = Max. Fuel Usage (kgal/hr) x Emission Factor (lbs/kgal) x Operation Hour Limit (hrs/yr) x 1 ton/2000 lbs x 2 units

Heat Input Capacity

308

MMBtu/hr
Page 6 of 16 SOB App A

Appendix A: Emission Calculations

HAP Emissions

From Two (2) 308 MMBtu/hr Auxiliary Boilers

Company Name: Navajo Generating Station

Address: 5 miles east of Page, off U.S. Highway 98, Page, AZ 86040

Permit No.: NN-OP-15-06

Reviewer: ERG/YC

Date: September 4, 2015

Max. Fuel Usage Operation Hour Limit*

(kgal/hr) (hrs/yr)

(each) 2.24 (each) 876

Pollutant

Chloride Nickel Fluoride Vanadium Formaldehyde Total HAPs

Emission Factor in lbs/kgal 3.47E-01 8.45E-02 3.73E-02 3.18E-02 3.30E-02 6.05E-01

Potential to Emit in tons/yr for 2 units 0.68 0.17 0.07 0.06 0.06 1.19

Emission factors are from AP-42, Tables 1.3-9 and 1.3-11 (AP-42, 09/98). 

The emission factor for total HAPs is the sum of the emission factors for organic HAP and metals.

* Pursuant to 40 CFR 63.7555(d)(3) (NESHAP, Subpart DDDDD), limited use boilers means boilers that limit the annual capacity factor to less than or equal to 10 percent

Methodology

PTE (tons/yr) = Max. Fuel Usage (kgal/hr) x Emission Factor (lbs/kgal) x Operation Hour Limit (hrs/yr) x 1 ton/2000 lbs x 2 units

308

Heat Input Capacity

MMBtu/hr
Page 7 of 16 SOB App A

Appendix A: Emission Calculations

PM, PM10, and PM2.5 Emissions 

From Coal Handling Operations 

Company Name: Navajo Generating Station

Address: 5 miles east of Page, off U.S. Highway 98, Page, AZ 86040

Permit No.: NN-OP-15-06

Reviewer: ERG/YC

Date: September 4, 2015

Unit Description Number of 

Units

Max. Capacity 

(tons/hr/unit)

PM Emission 

Factor* 

(lbs/ton)

PM10 

Emission 

Factor* 

(lbs/ton)

PM2.5 

Emission 

Factor* 

(lbs/ton)

Control Method Control Efficiency 

(%)

PTE of PM after 

Control (tons/yr)

PTE of PM10 after 

Control (tons/yr)

PTE of PM2.5 after 

Control (tons/yr)

Railcar Unloading 1 10,000 0.00010 0.00010 0.00010 Wet Dust Suppression 50.0% 2.190 2.190 2.190

Feeders 12 200 0.00014 4.60E-05 1.30E-05 Wet Dust Suppression 50.0% 0.736 0.242 0.068

Conveyors BC-1 through BC-4 4 1,800 0.00014 4.60E-05 1.30E-05 Dust Collector DC-8 99.0% 0.044 0.015 0.004

Conveyor BC-4A 1 100 0.00014 4.60E-05 1.30E-05 Dust Collector DC-8 99.0% 0.001 0.000 0.000

Conveyors BFD-5A and BC-5 2 1,800 0.00014 4.60E-05 1.30E-05 Dust Collector DC-8 99.0% 0.022 0.007 0.002

Conveyor BC-6 1 1,500 0.00014 4.60E-05 1.30E-05 Dust Collector DC-8 99.0% 0.009 0.003 0.001

Conveyors BC-6A through BC-6C 3 1,800 0.00014 4.60E-05 1.30E-05 Wet Dust Suppression 50.0% 1.656 0.544 0.154

Conveyor BC-7 1 1,500 0.00014 4.60E-05 1.30E-05 Wet Dust Suppression 50.0% 0.460 0.151 0.043

Yard Surge Bin YSB-1 1 1,800 0.00014 4.60E-05 1.30E-05 Dust Collector DC-8 99.0% 0.011 0.004 0.001

Conveyors BC-8A and BC-8B 2 1,500 0.00014 4.60E-05 1.30E-05 Dust Collector DC-8 99.0% 0.018 0.006 0.002

Screens BC-8AS and BC-8BS 2 1,500 0.00220 7.40E-04 5.00E-05 Dust Collector DC-8 99.0% 0.289 0.097 0.007

Plant Surge Bin PSB-1 1 3,000 0.00014 4.60E-05 1.30E-05 Dust Collector DC-5 99.0% 0.018 0.006 0.002

Conveyors BC-9A and BC-9B 2 1,500 0.00014 4.60E-05 1.30E-05 Dust Collector DC-5 99.0% 0.018 0.006 0.002

Conveyors BC-10A and BC-10B 2 1,500 0.00014 4.60E-05 1.30E-05 Dust Collector DC-5 99.0% 0.018 0.006 0.002

Three (3) enclosed cascading 

conveying systems 3 1,500 0.00014 4.60E-05

1.30E-05

Dust Collectors DC-1 through 

DC-4, DC-6, and DC-7 99.0%

0.028 0.009 0.003

Silos 1A through 1G 7 3,000 0.00014 4.60E-05 1.30E-05 Dust Collector/Baghouse 99.0% 0.129 0.042 0.012

Silos 2A through 2G 7 3,000 0.00014 4.60E-05 1.30E-05 Dust Collector/Baghouse 99.0% 0.129 0.042 0.012

Silos 3A through 3G 7 3,000 0.00014 4.60E-05 1.30E-05 Dust Collector/Baghouse 99.0% 0.129 0.042 0.012

Total 5.91 3.41 2.51

* The emission factors are from AP-42, Table 11.19.2-2 (08/04).

 Since the coal received at this facility has high moisture content (6.9%), the controlled emission factors in AP-42, Table 11.19.2-2 are used in the PTE calculations.

Methodology

PTE of PM/PM10/PM2.5 after Control (tons/yr) = Number of Units x Max. Capacity (tons/hr/unit) x Emission Factor (lbs/ton) x 8760 hrs/yr x 1 ton/2000 lbs x (1-Control Efficiency)
Page 8 of 16 SOB App A

Appendix A: Emission Calculations

PM, PM10, and PM2.5 Emissions 

From the Coal Storage Piles (Fugitive Emissions)

Company Name: Navajo Generating Station

Address: 5 miles east of Page, off U.S. Highway 98, Page, AZ 86040

Permit No.: NN-OP-15-06

Reviewer: ERG/YC

Date: September 4, 2015

1. Emission Factors:

According to AP-42, Chapter 13.2.4 - Aggregate Handling and Storage Piles (11/06), the PM/PM10 emission factors for 

 aggregate handling process can be estimated from the following equation:

Ef = k x 0.0032 x (U/5)1.3

 (M/2)1.4

where:

Ef = Emission Factor (lbs/ton)

k = Particle size multiplers = 0.74 for PM, 0.35 for PM10, and 0.053 for PM2.5

U = Mean wind speed (mph) = 3.2 mph (provided by the source based on the data in 1999)

M = Moisture content (%) = 3 % (provided by the source)

Therefore,

PM Emission Factor = 0.00075 lbs/ton 

PM10 Emission Factor = 0.00036 lbs/ton

PM 2.5 Emission Factor = 0.00005 lbs/ton

2. Potential to Emit PM/PM10/PM2.5 after Control:

Max. Throughput Rate: 3,300 tons/hr

Control Efficiency : 50% for water suppression

PTE of PM after Control (tons/yr) = 3,300 tons/yr x 0.00075 lbs/ton x 8760 hr/yr x 1 ton/2000 lbs x (1-50%) = 5.43 tons/yr

PTE of PM10 after Control (tons/yr) = 3,300 tons/yr x 0.00036 lbs/ton x 8760 hr/yr x 1 ton/2000 lbs x (1-50%) = 2.57 tons/yr

PTE of PM2.5 after Control (tons/yr) = 3,300 tons/yr x 0.00005 lbs/ton x 8760 hr/yr x 1 ton/2000 lbs x (1-50%) = 0.39 tons/yr
Page 9 of 16 SOB App A

Appendix A: Emission Calculations

PM, PM10, and PM2.5 Emissions 

From Limestone Handling System

Company Name: Navajo Generating Station

Address: 5 miles east of Page, off U.S. Highway 98, Page, AZ 86040

Permit No.: NN-OP-15-06

Reviewer: ERG/YC

Date: September 4, 2015

Unit Description Number of Unit Max. Capacity 

(tons/hr)

 PM Emission 

Factor* (lbs/ton)

 PM10 Emission 

Factor* (lbs/ton)

 PM2.5 

Emission 

Factor* 

(lbs/ton)

Control 

Efficiency (%)

PTE of PM 

(tons/yr)

PTE of PM 

(tons/yr)

PTE of PM2.5 

(tons/yr)

Truck Unloading 2 38.0 0.0001 0.0001 0.0001 0.00 0.03 0.03 0.03

Feeders 2 36.0 0.0030 0.0011 0.0011 0.00 0.95 0.35 0.35

Cleanout Conveyors 2 5.00 0.0030 0.0011 0.0011 0.00 0.13 0.05 0.05

Ball Mills 2 36.0 0.0054 0.0024 0.0024 0.00 1.70 0.76 0.76

Total 2.81 1.19 1.19

* The emission factora are from AP-42, Table 11.19.2-2 (08/04). Assume PM2.5 emission factors are equal to PM10 emission factors.

Methodology

PTE of PM/PM10/PM2.5 after control (tons/yr) = Num. of Units x Max. Capacity (tons/hr) x Emission Factor (lbs/ton) x 8760 hr/yr x 1 ton/2000 lbs x (1 - control efficiency)

Dust Collector ID Grain Loading 

(gr/acfm)

Flow Rate 

(acfm)

Controlled 

PM/PM10/PM2.5 

Emissions 

(lbs/hr)

Controlled 

PM/PM10/PM2.5 

Emissions 

(tons/yr)

Control 

Efficiency (%)

Uncontrolled 

PM/PM10/PM2.5 

Emissions 

(tons/yr)

DC-9 0.001 17,950 0.15 0.67 99% 67.4

DC-10 0.001 17,950 0.15 0.67 99% 67.4

DC-11 0.001 12,000 0.10 0.45 99% 45.1

Total 1.80 180

Methodology

Controlled Emissions (lbs/hr) = Grain Loading (gr/acfm) x Flow Rate (acfm) x 60 mins/hr x 1 lb/7000 gr

Controlled Emissions (tons/yr) = Controlled Emissions (lbs/hr) x 8760 hrs/yr x 1 ton/2000 lbs

Uncontrolled Emissions (tons/yr) = Controlled Emissions (tons/yr) / (1 - Control Efficiency)

PTE of PM after Control = 2.81 tons/yr + 1.80 tons/yr = 4.61 tons/yr

PTE of PM10 after Control = 1.19 tons/yr + 1.80 tons/yr = 2.98 tons/yr

PTE of PM2.5 after Control = 1.19 tons/yr + 1.80 tons/yr = 2.98 tons/yr
Page 10 of 16 SOB App A

Appendix A: Emission Calculations

PM, PM10, and PM2.5 Emissions 

From the Limestone Storage Piles (Fugitive Emissions)

Company Name: Navajo Generating Station

Address: 5 miles east of Page, off U.S. Highway 98, Page, AZ 86040

Permit No.: NN-OP-15-06

Reviewer: ERG/YC

Date: September 4, 2015

1. Emission Factors:

According to AP-42, Chapter 13.2.4 - Aggregate Handling and Storage Piles (11/06), the PM/PM10 emission factors for 

 aggregate handling process can be estimated from the following equation:

Ef = k x 0.0032 x (U/5)1.3

 (M/2)1.4

where:

Ef = Emission Factor (lbs/ton)

k = Particle size multiplers = 0.74 for PM, 0.35 for PM10, and 0.053 for PM2.5

U = Mean wind speed (mph) = 3.2 mph (provided by the source based on the data in 1999)

M = Moisture content (%) = 1 % (provided by the source)

Therefore,

PM Emission Factor = 0.0035 lbs/ton

PM10 Emission Factor = 0.0017 lbs/ton

PM2.5 Emission Factor = 0.0003 lbs/ton

2. Potential to Emit PM/PM10/PM2.5 after Control:

Max. Throughput Rate: 600 tons/yr 

Control Efficiency : 50% for water suppression

PTE of PM after Control (tons/yr) = 600 tons/yr x 0.0035 x 8760 hr/yr x 1 ton/2000 lbs x (1-50%) = 4.60 tons/yr

PTE of PM10 after Control (tons/yr) = 600 tons/yr x 0.0035 x 8760 hr/yr x 1 ton/2000 lbs x (1-50%) = 2.17 tons/yr

PTE of PM2.5 after Control (tons/yr) = 600 tons/yr x 0.0003 x 8760 hr/yr x 1 ton/2000 lbs x (1-50%) = 0.33 tons/yr
Page 11 of 16 SOB App A

Appendix A: Emission Calculations

PM, PM10, PM2.5, and HAP Emissions 

From the Fly Ash Handling System

Company Name: Navajo Generating Station

Address: 5 miles east of Page, off U.S. Highway 98, Page, AZ 86040

Permit No.: NN-OP-15-06

Reviewer: ERG/YC

Date: September 4, 2015

Unit Description Number of Units Max. Capacity 

(tons/hr/unit)

PM Emission 

Factor* 

(lbs/ton)

PM10 Emission 

Factor* (lbs/ton)

PM2.5 

Emission 

Factor* 

(lbs/ton)

Control Method Control 

Efficiency (%)

PTE of PM after 

Control (tons/yr)

PTE of PM10 after 

Control (tons/yr)

PTE of PM2.5 after 

Control (tons/yr)

Fly Ash Silos 2 46 2.20 2.20 2.20 Dust Collectors 99.0% 8.87 8.87 8.87

Truck Loading for Fly Ash 2 38 0.61 0.61 0.61 Dust Collectors 90.0% 20.3 20.3 20.3

Total 29.2 29.2 29.2

* The emission factors are from AP-42, Table 11.17-4 for Lime Manufacturing Process (02/98).

 Assume the PM10 and PM2.5 emissions are equal to PM emissions. 

Methodology

PTE of PM/PM10/PM2.5 after Control (tons/yr) = Num of Units x Max. Capacity (tons/hr/unit) x Emission Factor (lbs/ton) x 8760 hr/yr x 1 ton/2000 lbs x (1-Control Efficiency)

Potential to Emit HAPs

HAP

HAP 

Concentration* 

(ton per ton ash)

PTE of HAP 

(tons/yr)

Beryllium 6.097E-06 1.78E-04

Chromium 2.485E-05 7.25E-04

Lead 2.650E-05 7.73E-04

Manganese 1.372E-04 4.00E-03

Nickel 2.893E-05 8.44E-04

Total HAPs 6.52E-03

*HAP concentration values are based on the 4/26/99 NGS coal analysis data.

Methodology

PTE of HAP after Control (tons/yr) = PTE of PM after Control (tons/yr) x HAP Concentration (ton/ton of ash)
Page 12 of 16 SOB App A

Appendix A: Emission Calculations

PM, PM10, and PM2.5 Emissions 

From the Soda Ash/Lime Handling Systems

Company Name: Navajo Generating Station

Address: 5 miles east of Page, off U.S. Highway 98, Page, AZ 86040

Permit No.: NN-OP-15-06

Reviewer: ERG/YC

Date: September 4, 2015

Unit Description Number of 

Units

Max. Capacity 

(tons/hr/unit)

PM/PM10/PM2.5 

Emission Factor* 

(lbs/ton)

PTE of 

PM/PM10/PM2.5 

before Control 

(tons/yr)

Control Method Control 

Efficiency (%)

PTE of 

PM/PM10/PM2.5 

after Control 

(tons/yr)

Soda Ash Silos 4 0.40 2.20 15.4 Dust Collector 99.0% 0.15

Lime Silos 2 0.57 2.20 11.0 Baghouse 99.0% 0.11

Total 26.4 0.26

* The emission factors are from AP-42, Table 11.17-4 for Lime Manufacturing Process (02/98).

 Assume the PM10 and PM2.5 emissions are equal to PM emissions. 

Methodology

PTE of PM/PM10/PM2.5 before Control (tons/yr) = Number of Units x Max. Capacity (tons/hr/unit) x Uncontrolled Emission Factor (lbs/ton) x 8760 hrs/yr x 1 ton/2000 lbs

PTE of PM/PM10/PM2.5 after Control (tons/yr) = PTE of PM/PM10 before Control (tons/yr) x (1-Control Efficiency)
Page 13 of 16 SOB App A

Appendix A: Emission Calculations

PM, PM10, and PM2.5 Emissions 

From the Cooling Towers

Company Name: Navajo Generating Station

Address: 5 miles east of Page, off U.S. Highway 98, Page, AZ 86040

Permit No.: NN-OP-15-06

Reviewer: ERG/YC

Date: September 4, 2015

1. Process Description:

Circulation Flow Rate: 813,000 gal/min (6 cooling towers total)

Total Drift: 0.0009% of the circulating flow (provided by the source)

Total Dissolved Solids: 12,000 ppm 

Density: 8.328 lbs/gal

% Not Deposited on Site: 10% (provided by the source)

2. Potential to Emit PM/PM10/PM2.5:

Assume PM emissions are equal to PM10 emissions.

 PTE of PM/PM10/PM2.5 (Ibs/hr) = 813,000 gal/min x 60 min/hr x 0.0009% x 8.328 lbs/gal x 12,000 ppm x 1/1,000,000 ppm x 10% = 4.39 lbs/hr

 PTE of PM/PM10/PM2.5 (tons/yr) = 4.40 lbs/hr x 8760 hrs/yr x 1 ton/2000 lbs = 19.2 tons/yr
Page 14 of 16 SOB App A

Appendix A: Emission Calculations

Fugitive Emissions 

From Unpaved Roads

Company Name: Navajo Generating Station

Address: 5 miles east of Page, off U.S. Highway 98, Page, AZ 86040

Permit No.: NN-OP-15-06

Reviewer: ERG/YC

Date: September 4, 2015

1. Emission Factors:

According to AP42, Chapter 13.2.2 - Unpaved Roads (11/06), the PM/PM10/PM2.5 emission factors for unpaved roads

 can be estimated from the following equation:

E = k x (s/12)a x (w/3)b

 x (365-p)/365

where:

E = emission factor (lb/vehicle mile traveled)

s = surface material silt content (%) = 5.1 % (AP-42, Table 13.2.2-1)

w = mean vehicle weight (tons) = 78.1 tons (see the calculations below)

k = empirical constant = 4.9 for PM, 1.5 for PM10, and 0.15 for PM2.5

a = empirical constant = 0.7 for PM, 0.9 for PM10, and 0.9 for PM2.5

b = empirical constant = 0.45

p = number of days per year with 0.01 inches precipitation 60 (see Fig 13.2.2-1 in AP42)

PM Emission Factor = 4.9 x (5.1/12)0.7 x (78.1/3)0.45 x (365-60)/365 = 9.8 lbs/mile

PM10 Emission Factor = 1.5 x (5.1/12)0.9 x (78.1/3)0.45 x (365-60)/365 = 2.52 lbs/mile

PM2.5 Emission Factor = 0.15 x (5.1/12)0.9 x (78.1/3)0.45 x (365-60)/365 = 0.25 lbs/mile

2. Potential to Emit (PTE) of PM/PM10/PM2.5 Before Control from Unpaved Roads:

Number of 

Units

Ave. Vehicle 

Weight* 

Vehicle Miles 

Traveled* (VMT)

Total Vehicle 

Miles Traveled 

(VMT)

Traffic 

Component

Component 

Vehicle 

Weight PTE of PM PTE of PM10 PTE of PM2.5

(tons) (miles/day/unit) (miles/yr) (%) (tons) (tons/yr) (tons/yr) (tons/yr)

Service/Fuel Truck 1 16.5 15.0 5,475 2.44% 0.40 26.7 6.89 0.69

Service/Fuel Truck 1 13.2 18.0 6,570 2.93% 0.39 32.0 8.3 0.83

Ash Trucks 3 102 90.0 98,550 44.0% 44.8 480 124 12.4

Ash Truck 1 102 12.0 4,380 1.95% 1.99 21.4 5.51 0.55

D65 Dozer 1 22.0 5.00 1,825 0.81% 0.18 8.9 2.30 0.23

D31 Dozer 1 8.00 2.00 730 0.33% 0.03 3.56 0.92 0.09

Rubber Tire Dozer 1 33.5 1.00 365 0.16% 0.05 1.78 0.46 0.05

13 -Yard Loader 1 72.0 7.00 2,555 1.14% 0.82 12.5 3.21 0.32

6-Yard Loader 1 24.0 2.00 730 0.33% 0.08 3.56 0.92 0.09

2.5-Yard Loaders 2 12.5 2.00 1,460 0.65% 0.08 7.12 1.84 0.18

7-Yard Loader 1 54.5 3.00 1,095 0.49% 0.27 5.34 1.38 0.14

8,000-Gallon Waterpulls 1 36.5 30.0 10,950 4.88% 1.78 53.4 13.8 1.38

12,000-Gallon Waterpulls 1 115 127 46,355 20.7% 23.8 226 58.3 5.83

12-Yard Crystallizer Trucks 3 13.0 2.00 2,190 0.98% 0.13 10.7 2.75 0.28

12-Yard Dump Trucks 4 11.6 1.00 1,460 0.65% 0.08 7.12 1.84 0.18

14G Grader 1 28.0 10.0 3,650 1.63% 0.46 17.8 4.59 0.46

EI 300 Excavator 1 34.0 0.14 51 0.02% 0.01 0.25 0.06 0.01

140H Grader 1 19.8 1.00 365 0.16% 0.03 1.78 0.46 0.05

Road Trucks 2 11.0 1.00 730 0.33% 0.04 3.56 0.92 0.09

724 Vac Truck 1 19.8 3.00 1,095 0.49% 0.10 5.34 1.38 0.14

2.5 Yar Loader (928) 3 12.5 2.00 2,190 0.98% 0.12 10.7 2.75 0.28

NPG-797 Bucket Truck 1 20.6 40.0 14,600 6.51% 1.34 71.2 18.36 1.84

NPG-733 Bucket Truck 1 14.6 46.0 16,790 7.49% 1.09 81.9 21.12 2.11

224,161 100% 78.1 1,093 282 28.2

* This information is provided by the source.

Methodology

Component Vehicle Weight = Ave. Vehicle Weight (tons) x Traffic Component (%)

 (Note that the summation of the component vehicle weight equals the Mean Vehicle Weight.)

VMT(miles/yr) = VMT (miles/day/unit) x 365 days/yr x Number of Units

PTE of PM/PM10/PM2.5 (tons/yr) = VMT (miles/yr) x Emission Factor (lbs/mile) x 1 ton/ 2000 lbs

3. Potential to Emit (PTE) of PM/PM10/PM2.5 after Control from Unpaved Roads:

Control Efficiency : 50% for continuous water suppression

PTE of PM after Control = 1,093 tons/yr x (1-50%) = 546 tons/yr

PTE of PM10 after Control = 282 tons/yr x (1-50%) = 141 tons/yr

PTE of PM2.5 after Control = 28.2 tons/yr x (1-50%) = 14.1 tons/yr

Total 

Vehicle Type
Page 15 of 16 SOB App A

Appendix A: Emission Calculations

Internal Combustion Engines

From the Diesel Emergency Generators

Company Name: Navajo Generating Station

Address: 5 miles east of Page, off U.S. Highway 98, Page, AZ 86040

Permit No.: NN-OP-15-06

Reviewer: ERG/YC

Date: September 4, 2015

Operation Limit*

 (hrs/yr)

(9 units total) 500

PM PM10/PM2.5 SO2 NOx VOC CO

Emission Factor in lb/HP-hr 2.20E-03 2.20E-03 2.05E-03 3.10E-02 2.47E-03 6.68E-03

Potential to Emit (PTE) in tons/yr 1.57 1.57 1.47 22.2 1.77 4.78

Emission factors are from AP-42, Table 3.3-1 (10/96). 

Assume PM10/PM2.5 emissions equal PM emissions. TOC (total organic compounds) emissions equal VOC emissions.

Note: As defined in the September 6, 1995 memorandum from John S. Seitz of US EPA on the subject of "Calculating Potential to Emit for 

Emergency Generators", an emergency generator's sole function is to provide back-up power when power from the local utility is interrupted. 

The only circumstances under which an emergency generator would operate when utility power is available are during operator training or

brief maintenance checks. The generator's potential to emit is based on an operating time of 500 hours per year as set forth in the EPA memo.

Methodology

PTE (tons/yr) = Power Output (HP) x Emission Factor (lb/HP-hr) x Operation Limit (hr/yr) x 1 ton/2000 lbs

Pollutant

Power Output

Horse Power (HP)

2,861
Page 16 of 16 SOB App A

Appendix A: Emission Calculations

PTE Summary

Company Name: Navajo Generating Station

Address: 5 miles east of Page, off U.S. Highway 98, Page, AZ 86040

Permit No.: NN-OP-15-06

Reviewer: ERG/YC

Date: September 4, 2015

Limited Potential To Emit after Control

Emission Units PM PM10 PM2.5 SO2 NOx VOC CO Total HAPs

Boiler U1 1,947 1,097 488 3,246 7,789 75.3 4,868 22.7

Boiler U2 1,947 1,097 488 3,246 7,789 75.3 4,868 22.7

Boiler U3 1,947 1,097 488 3,246 7,789 75.3 4,868 22.7

Auxiliary Boilers 3.92 1.96 0.49 13.9 47.1 0.39 9.81 1.19

Coal Handling Operations 5.91 3.41 2.51 - - - - -

Coal Piles (Fugitive) 5.43 2.57 0.39 - - - - -

Limestone Handling Operations 4.61 2.98 2.98 - - - - -

Limestone Piles (Fugitive) 4.60 2.17 0.33 - - - - -

Fly Ash Handling Operations 29.2 29.2 29.2 - - - - 0.01

Soda Ash/Lime Handling Operations 0.26 0.26 0.26 - - - - -

Cooling Towers 19.2 19.2 19.2 - - - - -

PAC Storage Silos* 0.90 0.90 0.90 - - - - -

Unpaved Roads associated with PAC and 1.28 0.33 0.03 - - - - -

 CaBr2 delivery (Fugitive)*

Unpaved Roads (Fugitive) 546 141 14.1 - - - - -

Emergency Generators (Insignificant) 1.57 1.57 1.57 1.47 22.2 1.77 4.78 Negligible

Other Insignificant Activities** 15.3 15.3 15.3 - - 5.00 - Negligible

Total PTE (tons/yr) 6,481 3,513 1,550 9,752 23,437 233 14,620 69.3

Note: (*) The PTE information for these units is from Tribal NSR Permit #T-0004-NN, issued on 08/26/15.

 (**) PM10 emissions are from the welding and the abrasive blasting operations and are based on the information provided in the permit application received on 

 01/04/13. Assume PM10 emissions are equal to PM/PM2.5 emissions. VOC/HAP emissions are the estimated emissions from the parts cleaning, surface 

 coating operations, and the storage tanks. 
Dust Control Plan

For

Navajo Generating Station

Pursuant to the

Source-Specific

Federal Implementation Plan

40 CFR Part 49

Prepared By:

SALT RIVER PROJECT

Navajo Generating Station

P.O. Box 850

Page, AZ 86040

February 2015
Table of Contents

1. INTRODUCTION AND PURPOSE

2. FACILITY DETAILS

3. GEOGRAPHY AND CLIMATE

4. DUST SUPPRESSION METHODS 

Federal Implementation Plan Requirements - 40 CFR Part 49 §49.24(d)(3)

4.1 ROADWAYS

4.2 MATERIAL STORAGE

4.3 COAL HANDLING

4.4 FLY ASH HANDLING

4.5 LIMESTONE HANDLING

Navajo Nation EPA Title V Permit # NN-ROP-05-06, Section II.D. NSPS Subpart OOO

5. INSPECTIONS

6. RECORDKEEPING AND REPORTING

7. ROADWAY EQUIPMENT

8. TRAINING

9. ATTACHMENTS

9.1 Facility Map

9.2 Weekly Inspection Forms

9.3 Visible Emissions Form
1.0 INTRODUCTION AND PURPOSE

Salt River Project’s (SRP’s) Navajo Generating Station (NGS) facility is committed to 

responsible and sustainable stewardship of the environment; and compliance with the 

requirements of the United States Environmental Protection Agency’s (EPA’s) Federal 

Implementation Plan (FIP) for NGS, recorded in the Federal Register under 40 CFR Part 49. This 

Dust Control Plan (DCP) describes methods and procedures to minimize emissions from point 

and non-point dust sources and maintain compliance with the FIP.

FIP conditions in 40 CFR Part 49 §49.24(d)(3) specify that:

“Each owner or operator shall operate and maintain the existing dust suppression 

methods for controlling dust from the coal handling and storage facilities. Within 90 

days after promulgation of these regulations the owner or operator shall submit to the 

Regional Administrator a description of the dust suppression methods for controlling 

dust from the coal handling and storage facilities, fly ash handling and storage, and 

road sweeping activities. Each owner or operator shall not emit dust with opacity 

greater than 20% from any crusher, grinding mill, screening operation, belt conveyor, 

truck loading or unloading operation, or railcar unloading station.”

2.0 FACILITY DETAILS

NGS is a participant owned generating plant managed by SRP. NGS is located on leased land 5

miles southeast of Page Arizona at 4365 feet (elevation). The participants are U.S. Bureau of 

Reclamation (24.3% ownership), Los Angeles Department of Water and Power (21.2%), Salt 

River Project (21.7%), Arizona Public Service (14.0%), Nevada Power (11.3%) and Tucson 

Electric Power Co. (7.5%). NGS is a three-unit coal fired power plant (supercritical design 

tangentially-fired boilers) generating 2250 net megawatts of power.

Bituminous coal is mined by Peabody Energy at the Black Mesa Mine Complex and delivered by 

electric rail to NGS. Coal is then transferred via enclosed conveyor systems for burning in the 

boilers or stacked out to a storage pile for later use. 

The management of coal combustion residues and the delivery of limestone for the SO2 scrubbers 

is contracted to a third party entity but SRP remains the responsible party for truck loading and 

unloading operations, material transfer, storage, and disposal activities. Coal combustion residues 

include flyash, bottom ash, and scrubber byproducts. Bottom ash and scrubber byproducts are 

handled in a wet state which minimizes the potential for dust emissions and these materials are 

not addressed in the FIP and in this document.

3.0 GEOGRAPHY AND CLIMATE

NGS is located in an arid desert environment receiving an annual average of seven and half 

inches of precipitation. The surrounding geologic formations include outcroppings of the Carmel 

formation, Page Sandstone, and Navajo Sandstone. Weathering of these formations have created 

substrates of unconsolidated aeolian sands and partially stabilized dune deposits with sparse 

vegetation.
4.0 DUST SUPPRESSION METHODS 

The FIP requires in 40 CFR Part 49 §49.24(d)(3) a description of the dust suppression methods 

for coal handling and storage facilities, fly ash handling and storage, and road sweeping activities.

The tables contained in this section outline preventive and mitigating control measures as 

guidelines to minimize dust emissions from paved and unpaved roads, storage piles, and the 

material handling related to coal, fly ash, and limestone. 

4.1 Roadways

Dust emissions from roadways are mitigated using control measures outlined below. Main 

trafficked areas are sprayed with water daily (weather permitted) and speed limits are observed. 

During winter months, ice formation may preclude water spraying due to safety consideration.

Roadway Non-Point Sources: One or more of the following control measures will be 

implemented to minimize dust emissions from roadway sources. 

TABLE 1.0 Control Measure Guidelines:

Source: Roadway Dust Control Measures

Paved Roads:

Traffic Activity

1. Water spray roads

2. Speed reduction

3. Limit Traffic

4. Sweeping of roads

Unpaved Roads:

Traffic Activity

1. Water spray roads

2. Speed reduction

3. Limit traffic

4. Gravel surface

5. Chemical stabilization

Carryout 1. Clean vehicles before entering roadway

2. Pave access road near plant site exit

3. Rapid cleanup after spill events

Monitor: Verify control measures weekly.
4.2 Material Storage 

Table 2.0 Control Measure Guidelines:

Material Storage

Control techniques applicable to outdoor material storage piles fall into distinct categories 

as related to handling operations (including traffic around piles) and mitigating wind 

erosion. In both cases, the control can be achieved by implementing one or more of the 

following strategies: (a) source extent reduction, (b) source improvement related to work 

practices and transfer equipment (load-in and load-out operations), and (c) surface 

treatments.

Material Disturbance and Wind Erosion Control Measures:

Source control 1. Minimize exposed surface area

2. Minimize surface disturbances and material handling 

Source improvement 1. Reduce drop height when handling material

2. Maintain moisture and crust, as applicable

3. Shelter from wind, as applicable

Surface treatment 1. Water Spraying, as applicable

2. Chemical stabilization

Monitor: Verify control measures weekly.

4.3 Coal Handling

SRP’s responsibilities extend to all aspects of coal handling and storage; this includes 

implementing dust control measures for the following:

Coal Handling Non-Point Sources: One or more of the following control measures will be 

implemented by NGS to minimize dust emissions from the potential sources listed below:

TABLE 3.0 Control Measure Guidelines:

Source: (Unit ID) Material Handling Control Measures

Material Handling: (CT1) 

Railroad car unloading 

operations

1. Shelter from wind - enclosure

2. Reduce drop height – minimum hopper level 

maintained

3. Watering spraying

(L1-L12) Twelve hopper 

feeders

1. Shelter from wind - enclosure

2. Water spraying

3. Chemical stabilization 

(BC-1) Belt Conveyor 1. Shelter from wind - enclosure

2. Water spraying

3. Chemical stabilization 

(BC-2) 1. Shelter from wind - enclosure

2. Maintain moisture

(BC-3) 1. Shelter from wind - enclosure

2. Maintain moisture

(BC-4) 1. Shelter from wind - enclosure

2. Maintain moisture

(BC-4A) 1. Shelter from wind - enclosure

2. Maintain moisture

(BFD-5A) 1. Shelter from wind - enclosure
Belt Feeder Deck 2. Maintain moisture

(BC-5) 1. Shelter from wind - enclosure

2. Maintain moisture

(BC-6A) 1 of 3 stacker / 

reclaimer reversible 

conveyers

1. Shelter from wind - enclosure

2. Water spraying

3. Chemical stabilization 

(BC-6B) 2 of 3 stacker 

conveyer only

1. Shelter from wind - enclosure

2. Maintain moisture

(BC-6C) 3 of 3 stacker / 

reclaimer reversible 

conveyers

1. Shelter from wind - enclosure

(BC-6) 1. Shelter from wind - enclosure

2. Water spraying

3. Chemical stabilization 

(BC-7) One conveyor to the 

emergency reclaim hopper

1. Shelter from wind - enclosure

2. Water spraying

3. Chemical stabilization 

Wind Erosion: (CS) Outdoor 

coal storage piles

1. Maintain moisture

2. Water spraying

3. Chemical stabilization

Monitor: Verify control measures weekly.

Coal Handling Point Sources: The potential sources listed in Table 4.0 utilize particulate control 

devices to control emissions. 

TABLE 4.0 Emission Control Devices:

Unit ID / Stack ID: Control Device Make / Size Stack Details

YSB-1 DC-8 (Sample Bldg 

– 100 feet 

elevation)

Peabody Lugar LT

(Air Flow

20,000 acfm)

Exit opening facing 

eastward on east 

side of EF-8. 

Opening: 1.5 feet by 

2 feet

BC-8A & BC-8B

BC-8A & BC-8B

screening operation

PSB-1 DE-5

(Cascade Enclosure 

- 135 feet 

elevation)

SIEMENS Dust 

Eliminator System

Exit opening is 

outside building

facing west. 

Opening: 3 feet by 3 

feet

BC-9A & BC-9B

BC-10A & BC-10B

CC-1A thru CC-9A; 

CC-1B thru CC-9B; 

BC-11A & BC-11B

SEE BELOW – The dust emissions from the cascading conveyors 

are also controlled by DE-1 through DE-4 and DE-6 & DE-7.

Silos 1A thru 1G DE-1 & DE-2

(Cascade Enclosure 

- 135 feet 

elevation)

SIEMENS and 

PR-1, SR-1 & EX-1

Exit opening is 

outside building 

facing east. 

Opening: 3 feet by 

3 feet
Silos 2A thru 2G DE-3 & DE-4

(Cascade Enclosure 

- 135 feet 

elevation)

SIEMENS and 

PR-2, SR-2 & EX-2

Exit opening is 

outside building 

facing east. 

Opening: 3 feet by 

3 feet

Silos 3A thru 3G DE-6 & DE-7

(Cascade Enclosure 

- 135 feet 

elevation)

SIEMENS and 

PR-3, SR-3 & EX-3

Exit opening is 

outside building 

facing east. 

Opening: 3 feet by 

3 feet

Monitor: Weekly visible emission observations will be recorded for each control device listed 

above that is operating. If visible emissions are observed, opacity readings will be conducted in 

accordance with EPA Method 9.

4.4 Fly Ash Handling

SRP’s responsibilities extend to all aspects of flyash handling and storage although some 

activities are managed by a third party contractor:

Fly Ash Non-point Sources: The activities in Table 5.0 are managed by a third party contractor

and activities in Table 5.1 are managed by SRP. One or more of the following control measures 

are implemented to minimize dust emissions from these potential sources. 

TABLE 5.0 Control Measure Guidelines:

Source: Material Handling and Roadway Control Measure(s)

Material Handling:

Silo 1 Loading

(open bed haul truck

loading operations)

1. Drop height reduction

2. Moisture retention, apply as needed

3. Wind sheltering, loading chute

Silo 2 Loading

(open bed haul truck 

loading operations)

1. Drop height reduction

2. Moisture retention, apply as needed

3. Wind sheltering, loading chute

Paved Roads:

Traffic Activity

1. Limit Traffic

2. Sweeping of roads

3. Water Flushing of roads

Carryout 1. Clean vehicles before entering roadway

2. Pave access road near site exit

3. Rapid cleanup after event

Spillage 1. Reducing overloaded trucks

2. Wetting materials being hauled

Unpaved Roads:

Traffic Activity

1. Water Suppression

2. Chemical stabilization

3. Speed reduction

4. Limit traffic

5. Gravel surface

TABLE 5.1 Control Measure Guidelines:

Source: Material Handling/Processing Control Measure(s)

Spillage (conveyance from

post-furnace to enclosed silos) 

1. Enclosure

2. Rapid cleanup after spill events
Monitor: Verify control measures weekly.

Flyash Point Sources: The potential sources listed in Table 6.0 are managed by SRP and utilize 

particulate control devices to control emissions.

TABLE 6.0 Emission Control Devices:

Unit ID / Stack ID: Control Device Make / Size Stack Details

Silo 1

(storage activity)

DC-S1/2

(baghouse on top of 

Silo 1)

Scientific Dust 

Collectors

EX Fan facing 

south on west end 

of baghouse.

Opening: 2.5 feet 

by 4 feet

Silo 2

(storage activity)

DC-S3

(baghouse on top of 

Silo 2)

Scientific Dust 

Collectors

EX Fan facing 

south on west end 

of baghouse. 

Opening: 2.5 feet 

by 4 feet

Silo 1 Loading

(enclosed fly ash 

trucks loading)

DC-S1/2

(baghouse on top of 

Silo 1)

Scientific Dust 

Collectors

Facing skyward on 

east side of 

baghouse. 

Opening: 1 foot by 

2 feet

Silo 2 Loading

(enclosed fly ash 

trucks loading)

DC-S3

(baghouse on top 

Silo 2)

Scientific Dust 

Collectors

EX Fan facing 

south on west end 

of baghouse.

Opening: 2.5 feet 

by 4 feet

Monitor: Weekly visible emission observations will be recorded for each control device listed 

above that is operating. If visible emissions are observed, opacity readings will be conducted in 

accordance with EPA Method 9.

4.5 Limestone Handling

All Limestone Non-Point and Point sources are managed in accordance with the NGS Title V 

Operating Permit, Section II.D. NSPS, Subpart OOO requirements.

Limestone Handling Non-point Sources:

Table 7.0 Control Measure Guidelines:

Source: Control Measure(s)

Material Handling:

Unloading Bay A and B 

(truck unloading operations)

Not Applicable - Truck dumping of non-metallic minerals into 

any screening operation, feed hopper, or crusher is exempt 

per 40 CFR 60.672(d)

LS – Limestone Storage Pile 1. Water suppression

2. Maintain visible surface crust

Monitor: Weekly observations will be recorded.
Limestone Handling Point Sources: The potential sources listed in Table 8.0 utilize particulate 

control devices to control emissions.

Table 8.0 Control Devices:

Unit ID / Stack ID: Control Device Make / Size Stack Details

O-LSH-HOP-A

DC-9

(Baghouse on SW 

corner of 

Limestone 

Handling)

Mac Equipment 

Company, Serial 

number 95-

FMCF361Filter, 

12X12X38.1 feet 

tall, 22,000 pounds 

and a design 

capacity of 18,000 

ACFM.

Facing skyward.

Opening: 34 inch 

diameter pipe

O-LSH-FDR-A

O-LSH-CNV-A

O-LSH-HOP-B

DC-10

(Baghouse on NE 

corner of 

Limestone

Handling)

Mac Equipment 

Company, Serial 

number 96-

MCF361Filter, 

12X12X38.1 feet 

tall, 22,000 pounds 

and a design 

capacity of 18,000 

ACFM.

Facing skyward.

Opening: 34 inch 

diameter pipe

O-LSH-FDR-B

O-LSH-CNV-B

O-LSH-SILO-A&B

DC-11

(Baghouse on W 

side of Limestone 

Prep Building)

Mac Equipment 

Company, Serial 

number 95-FMCF07-007, Model 

number 96-

MCF255Filter, 

10X10X32.2 feet 

tall, 9,200 pounds 

and a design 

capacity of 12,681 

ACFM.

Facing skyward.

Opening: 30 inch 

diameter pipe

Monitor: Weekly observations will be recorded.

Opacity limitations are as follows:

 No greater than 15% from any crusher without a capture system.

 No greater than 10% from any transfer point without a capture system.

 No greater than 7% from any stack emissions or building vent enclosing any transfer 

point or crushing operations.

 Truck dumping of nonmetallic minerals into any screening operations, feed hopper or 

crusher is exempt per 40 CFR 60.672(d).
4.5 Soda Ash and Lime Handling

All Soda Ash Point sources are managed in accordance with the FIP conditions in 40 CFR Part 49 

§49.24(d)(3).

Soda Ash and Lime Handling Point Sources: The potential sources listed in Table 9.0 utilize 

particulate control devices to control emissions.

Table 9.0

Control Devices:Unit 

ID / Stack ID:

Control Device Make / Size Stack Details

SAB-1A, SAB-2A, 

SAB-1B, SAB-2B 

(water treatment

soda ash storage 

activity)

DC-BH6

(baghouse on top of 

Bin 3)

Scientific Dust 

Collectors

Exhaust opening

facing south on top 

of baghouse.

Opening: 6” I.D.

LB-1 & LB-2

(water treatment

lime storage activity)

DC-BH7

(baghouse on top of 

Bin 1)

Scientific Dust 

Collectors

Exhaust opening

facing south on top 

of baghouse.

Opening: 6” I.D.

Monitor: Weekly observations will be recorded.

Opacity limitations are as follows:

 No greater than 20% from any capture system.
5.0 INSPECTIONS

The effectiveness of control measures will be evaluated using regular inspections and 

documentation of visible emissions, as applicable. Dust control devices will be operated and 

maintained with opacity emission limits specified in the Federal Implementation Plan - 40 CFR 

Part 49 §49.24(e)(8).

Inspections shall be performed weekly by trained and certified Method 9 observers. For nonpoint sources the inspectors shall document active control measures that are being used to 

minimize dust emissions. In the case of point sources, the observers shall perform visible 

emission observations. If visible emissions are observed, opacity readings will be conducted in 

accordance with EPA Method 9. 

See Section 9 – Weekly Inspection Forms

6.0 RECORD KEEPING AND REPORTING

SRP will maintain records of weekly inspection records, Method 9 certification training, and 

Method 9 observations. 

SRP will make reports as necessary in accordance with the Federal Implementation Plan - 40 

CFR Part 49 §49.24(f).

For excess emissions, SRP will notify the Navajo Environmental Protection Agency Director and 

the U.S. Environmental Protection Agency Regional Administrator by telephone or in writing 

within one business day. 

The notifications will be sent to the Director, Navajo Environmental Protection Agency, by mail 

to: P.O. Box 339, Window Rock, Arizona 86515, or by facsimile to: (928) 871–7996 (facsimile), 

and to the Regional Administrator, U.S. Environmental Protection Agency Region 9, by mail to

the attention of Mail Code: AIR–5, at 75 Hawthorne Street, San Francisco, California 94105, by 

facsimile to: (415) 947–3579 (facsimile), or by e-mail to:r9.aeo@epa.gov. 

A complete written report of the incident shall be submitted to the Regional Administrator within 

ten (10) working days after the event. This notification shall include the following information:

(i) The identity of the stack and/or other emissions points where excess emissions occurred;

(ii) The magnitude of the excess emissions expressed in the units of the applicable emissions 

limitation and the operating data and calculations used in determining the magnitude of the 

excess emissions;

(iii) The time and duration or expected duration of the excess emissions;

(iv) The identity of the equipment causing the excess emissions;

(v) The nature and cause of such excess emissions;

(vi) If the excess emissions were the result of a malfunction, the steps taken to remedy the 

malfunction and the steps taken or planned to prevent the recurrence of such malfunction; and

(vii) The steps that were taken or are being taken to limit excess emissions.
7.0 ROADWAY EQUIPMENT

2 – Water Truck

 Owner: HRI Make: Komatsu, Model Mega, 13,000 gallon capacity

 SRP RENTAL Make: International, Model 4300, 4,000 gallon capacity

1 – Water Pull

 Owner: SRP Make: Caterpillar, Model 621-G, 8,000 gallon capacity

2 – Ride-On Sweeper

 Owner: SRP Make: Tennet, Model 355-G, 14 cubic feet hopper volume

 Owner: SRP Make: Tennet, Model 830, 3.4 cubic yard hopper volume

1 – Vacuum Truck

 Owner: SRP Make: International, Supersucker Model 5227, 15 cubic yard capacity

8.0 TRAINING

At least two (2) on-site personnel will obtain EPA Method 9 certifications and receiving training 

regarding weekly inspections and provisions of this plan. A copy of the NGS FIP Dust Control 

Plan will be made available to plant personnel and the third party contractor responsible for 

handling coal combustion residues and limestone deliveries. 

9.0 ATTACHMENTS

9.1 Facility Map

9.2 Weekly Inspection Forms

9.3 Visible Emissions Form
Facility Map
Weekly Inspection Forms
WEEKLY INSPECTION FORMS

NGS FIP WEEKLY OBSERVATIONS – 20% OPACITY LIMIT

Certified 

Observer (Circle) Walter Begay Jon Adams LD Shakespear

Date: Signature:

SRP/NGS

Non-Point Sources (Coal Handling and Storage)

MATERIAL HANDLING AND STORAGE CONTROL MEASURES

Source (Unit ID) Control Measure(s) Implemented (Circle) Comments:

Material 

Handling: (CT1) 

Railroad car 

unloading 

operations

1. Shelter from wind - enclosure

2. Reduce drop height – minimum hopper level 

maintained

3. Water spraying

(L1-L12) Twelve 

hopper feeders

1. Shelter from wind - enclosure

2. Watering 

3. Chemical stabilization 

(BC-1) Belt 

Conveyor

1. Shelter from wind - enclosure

2. Water spraying

3. Chemical stabilization 

(BC-2) 1. Shelter from wind - enclosure

2. Maintain moisture

(BC-3) 1. Shelter from wind - enclosure

2. Maintain moisture

(BC-4) 1. Shelter from wind - enclosure

2. Maintain moisture

(BC-4A) 1. Shelter from wind - enclosure

2. Maintain moisture

(BFD-5A)

Belt Feeder Deck

1. Shelter from wind - enclosure

2. Maintain moisture

(BC-5) 1. Shelter from wind - enclosure

2. Maintain moisture

(BC-6A) 1 of 3 

stacker / reclaimer 

reversible 

conveyers

1. Shelter from wind - enclosure

2. Water spraying

3. Chemical stabilization 

(BC-6B) 2 of 3 

stacker conveyer 

only

1. Shelter from wind - enclosure

2. Maintain moisture

(BC-6C) 3 of 3 

stacker / reclaimer 

reversible 

conveyers

1. Shelter from wind - enclosure
SRP/NGS

Non-Point Sources (Coal Handling and Storage)

MATERIAL HANDLING AND STORAGE CONTROL MEASURES

Source (Unit ID) Control Measure(s) Implemented (Circle) Comments:

(BC-6) 1. Shelter from wind - enclosure

2. Water spraying

3. Chemical stabilization 

(BC-7) One 

conveyor to the 

emergency reclaim 

hopper

1. Shelter from wind - enclosure

2. Water spraying

3. Chemical stabilization 

Wind Erosion: 

(CS) Outdoor coal 

storage piles

1. Maintain moisture or visible crust

2. Water spraying

3. Chemical stabilization

Point Sources (Coal Handling and Storage)

PARTICULATE CONTROL DEVICES

Source (Unit ID) Control Device Is Control 

Device 

Operating? 

(Check one)

Is there VE? 

(Check one)

Was EPA 

Method 09 

conducted? 

(Check one)

YES NO YES NO YES* NO**

YSB-1

DC-8

BC-8A & BC-8B

BC-8A & BC-8B

screening operation

PSB-1

DE-5

BC-9A & BC-9B

BC-10A & BC-10B

CC-6A/6B &

Silos 1A thru 1C

(coal silos)

DE-1

CC-4A/4B, CC5A/5B &

Silos 1D thru 1G 

(coal silos)

DE-2

Cascade Enclosure PR-1 SR-1 EX-1 

* Note: Complete one Method 9 VE Observation Form for each control device if visible emissions are 

observed.

**Note: Method 9 VE Observation Form was not completed due to: Wind Direction / Sun Position / Other.

Explain:
SRP/NGS

Point Sources (Coal Handling and Storage - Continued)

PARTICULATE CONTROL DEVICES

Source (Unit ID) Control Device Is Control 

Device 

Operating? 

(Check one)

Is there VE? 

(Check one)

Was EPA 

Method 09 

conducted? 

(Check one)

YES NO YES NO YES* NO**

CC-3A/3B, CC11A/11B &

Silos 2A thru 1C

(coal silos)

DE-3

CC-1A/1B, CC2A/2B &

Silos 2D thru 1G 

(coal silos)

DE-4

Cascade Enclosure PR-2 SR-2 EX-2 

CC-7A/7B, CC8A/8B &

Silos 3A thru 1D

(coal silos)

DE-6

CC-9A/9B &

Silos 3E thru 1G 

(coal silos)

DE-7

Cascade Enclosure PR-3 SR-3 EX-3

Point Sources (Fly Ash Handling and Storage)

PARTICULATE CONTROL DEVICES

Source (Unit ID) Control Device Is Control Device 

Operating?

(Check one)

Is there VE? 

(Check one)

Was EPA 

Method 09 

conducted? 

(Check one)

YES NO YES NO YES* NO**

Silo 1 (ash silo

storage) DC-S1/2 

Silo 2 (ash silo

storage) DC-S3

* Note: Complete one Method 9 VE Observation Form for each control device if visible emissions are 

observed.

**Note: Method 9 VE Observation Form was not completed due to: Wind Direction / Sun Position / Other.

Explain:
SRP/NGS

Point Sources (Fly Ash Handling and Storage)

PARTICULATE CONTROL DEVICES

Source Control Device Is Control Device 

Operating?

(Check one)

Is there VE? 

(Check one)

Was EPA 

Method 09 

conducted? 

(Check one)

YES NO YES NO YES* NO**

Silo 1 Loading

(1 of 2 loading; 

enclosed trailer 

loadout)

DC-S1/2

Silo 2 Loading

(2 of 2 loading; 

enclosed trailer 

loadout)

DC-S3

* Note: Complete one Method 9 VE Observation Form for each control device if visible emissions are 

observed.

**Note: Method 9 VE Observation Form was not completed due to: Wind Direction / Sun Position / Other.

Explain:

Non-Point Sources (Fly Ash Handling and Storage)

MATERIAL HANDLING AND ROADWAY CONTROL MEASURES

Source Control Measure(s) Implemented (Circle) Comments:

Material 

Handling:

Silo 1 Loading

(2 of 2 loading; 

open bed haul truck 

loading operations)

1. Drop height reduction

2. Moisture retention, apply as needed

3. Wind sheltering, loading chute

Silo 2 Loading

(2 of 2 loading; 

open bed haul truck 

loading operations)

1. Drop height reduction

2. Moisture retention, apply as needed

3. Wind sheltering, loading chute

Paved Roads:

Traffic Activity

1. Limit Traffic

2. Sweeping of roads

3. Water Flushing of roads

Carryout 1. Clean vehicles before entering roadway

2. Pave access road near site exit

3. Rapid cleanup after event

Spillage 1. Reducing overloaded trucks

2. Wetting materials being hauled

Unpaved Roads:

Traffic Activity

1. Water suppression

2. Chemical stabilization

3. Speed reduction

4. Limit traffic

5. Gravel surface
SRP/NGS

Non-Point Sources (Fly Ash Handling and Storage)

MATERIAL HANDLING AND ROADWAY CONTROL MEASURES

Source Control Measure(s) Implemented (Circle) Comments:

Spillage

(conveyance from

post-furnace to 

enclosed silos)

1. Enclosure

2. Rapid cleanup after spill events

Non-Point Sources

PAVED ROADWAY CONTROL MEASURES

Source Control Measure(s) Implemented (Circle) Comments:

Paved Roads:

Traffic Activity

1. Water Spraying of Roads

2. Reduce Speed

3. Limit Traffic

4. Sweeping of roads

Carryout 1. Clean vehicles before entering roadway

2. Pave access road near site exit

3. Rapid cleanup after event

Non-Point Sources

UNPAVED ROADWAY CONTROL MEASURES

Source Control Measure(s) Implemented (Circle) Comments:

Unpaved Roads:

Traffic Activity

1. Watering

2. Chemical stabilization

3. Speed reduction

4. Limit traffic

5. Gravel surface

Point Sources (Soda Ash Handling and Storage)

PARTICULATE CONTROL DEVICES

Source (Unit ID) Control Device Is Control 

Device 

Operating? 

(Check one)

Is there VE? 

(Check one)

Was EPA 

Method 09 

conducted? 

(Check one)

YES NO YES NO YES* NO**

SAB-1A, SAB-2A, 

SAB-1B, SAB-2B 

(water treatment

soda ash storage 

activity)

DE-BH6

* Note: Complete one Method 9 VE Observation Form for each control device if visible emissions are 

observed.

**Note: Method 9 VE Observation Form was not completed due to: Wind Direction / Sun Position / Other.

Explain:
SRP/NGS

Point Sources (Lime Handling and Storage)

PARTICULATE CONTROL DEVICES

Source (Unit ID) Control Device Is Control 

Device 

Operating? 

(Check one)

Is there VE? 

(Check one)

Was EPA 

Method 09 

conducted? 

(Check one)

YES NO YES NO YES* NO**

LB-1 & LB-2

(water treatment

lime storage 

activity)

DE-BH7

NGS LIMESTONE WEEKLY OBSERVATIONS – 7, 10, 15 & 20% OPACTIY LIMITS

Point Sources (Limestone Handling and Storage)

PARTICULATE CONTROL DEVICES

Source (Unit ID) Control Device (LIMT) Is Control Device 

Operating?

(Check one)

Is there VE? 

(Check one)

Was EPA 

Method 09 

conducted? 

(Check one)

YES NO YES NO YES* NO**

O-LSH-HOP-A

O-LSH-FDR-A

O-LSH-CNV-A

DC-9 (7% Opacity Limit)

O-LSH-HOP-B

O-LSH-FDR-B

O-LSH-CNV-B

DC-10 (7% Opacity Limit)

O-LSH-SILOA&B DC-11 (7% Opacity Limit)

Point and Non-Point Sources (Limestone Handling and Storage)

MATERIAL HANDLING AND STORAGE MEASURES

Source CIRCLE Control Measures Implemented (LIMIT) Comments:

O-LSP-FDRA&B, O-LSPCNV-A&B 

1. Enclosures - Pt. Src. Opacity Limits: From

baghouses, stacks and bldg. vents/openings 7%

2. Non-Enclosed - Fugitive Src. Opacity Limits: From 

transfer pts. 10% / crushing 15%.

3. Dumping – Some activity is exempt

Limestone 

Storage Pile (LS) 1. Watering

2. Maintain visible crust

* Note: Complete one Method 9 VE Observation Form for each control device if visible emissions are 

observed.

**Note: Method 9 VE Observation Form was not completed due to: Wind Direction / Sun Position / Other.

Explain:
Visible Emissions Form
SRP/NGS VISIBLE EMISSION OBSERVATION FORM

Observation Date: _________________ Start Time: ______________ End Time: ___________

Process Equipment: LIMIT Process Control Device* (circle):

Limestone Handling System

Title V Condition: II.D.5.ii & II.D.6 7% DC9 DC10 DC11 or Bldg. Vents

Coal Material Handling

FIP Dust Control Plan Table 2.0 20% DE1 DE2 DE3 DE4 DE5 DE6 DE7 DC8 

Fly Ash Handling / Storage

FIP Dust Control Plan Table 3.0 20% DCS1/2 DCS3

Enclosed Trailer Loading

FIP Dust Control Plan Table 7.0 20% DCS1/2 DCS3

Soda Ash and Lime Handling

FIP Dust Control Plan Table 9.0 20% DEBH6 DEBH7

Plume Color: ______________ Plume Background: _________________ Sky: ________________

Wind Speed (mph): _________ Wind Direction (N-E-S-W): __________ Temperature (°F): _______

Stack Ht. - above 0 elev. (feet):_____Stack Distance and Ht. in relation to Observer (feet):________

Recording Observations. Opacity observations shall be recorded to the nearest 5 percent at 15-second intervals on an 

observational record sheet. A minimum of 24 observations shall be recorded. 

Each momentary observation recorded shall be deemed to represent the average opacity of emissions for a 15-second period.

Data Reduction. Opacity shall be determined as an average of 24 consecutive observations recorded at 15-second intervals. 

Divide the observations recorded on the record sheet into sets of 24 consecutive observations. A set is composed of any 24 

consecutive observations. Sets need not be consecutive in time and in no case shall two sets overlap. For each set of 24 

observations, calculate the average by summing the opacity of the 24 observations and dividing this sum by 24. 

Record the average opacity on a record sheet. 

Minute 0 second 15 sec 30 sec 45 sec Comments

1

2

3

4

5

6

Sum of opacity readings / 24 observations = Average opacity**

1

2

3

4

5

6

Sum of opacity readings / 24 observations = Average opacity**

*Note: Complete one sheet for one control device with emissions.

** Note: If Average Opacity is greater than LIMIT contact Paul Ostapuk and Operations IMMEDIATELY!

Observer: ___________________ Date:________________________________________
United States Environmental Protection Agency, Region IX

Air Division

75 Hawthorne Street

San Francisco, CA 94105

ACID RAIN PERMIT

Permit Number: NN 13-01

In accordance with the provisions of Title IV of the Clean Air Act and 40 C.F.R. 

Parts 72 through 77, this Acid Rain Permit is issued to: 

Salt River Project Agricultural Improvement and Power District

Navajo Generating Station (Plant Code 4941) 

Page, AZ

All terms and conditions of the permit are enforceable by EPA and citizens under 

the Clean Air Act. Please reference the permit number cited above in future 

correspondence regarding this facility.

 ___________________________ 

Date Deborah Jordan

Director, Air Division

EPA Region IX
Acid Rain Permit No. NN 13-01

PERMIT CONDITIONS

1. The permittee shall comply with all the applicable requirements of the Acid Rain 

Permit Application located in Appendix A.

2. The Permittee shall not discharge or cause the discharge of NOx from each 

pulverized coal-fired boiler (U1, U2, and U3) into the atmosphere in excess of 

0.40 lb/MMBtu of heat input on an annual average basis, calculated using the 

methods and procedures specified in 40 CFR Part 75, Appendix F, Section 8.

3. This Acid Rain permit incorporates the definitions of terms in 40 CFR Part 72.2.

4. This permit is valid for a term of five (5) years from the date of issuance unless a 

timely and complete renewal application is submitted to EPA at the following 

address: 

EPA Region IX

Permits Office (AIR-3)

75 Hawthorne St.

San Francisco, CA 94105

5. A timely renewal application is an application that is received at least six months 

prior to the permit expiration date. 
Acid Rain Permit No. NN 13-01

Appendix A

Acid Rain Permit Application








Attachment C - Page 1 of 24

Compliance, Monitoring, Testing, Notification, Recordkeeping, and 

Reporting Requirements under NESHAP, Subpart UUUUU for Coal- and 

Oil-Fired Electric Utility Steam Generating Units

[Based on the rule version dated as March 24, 2015]

Note: The requirements pertaining to Hg emissions are not applicable until April 16, 2016. 

I. GENERAL COMPLIANCE REQUIREMENTS

a. At all times you must operate and maintain any affected source, including associated air pollution 

control equipment and monitoring equipment, in a manner consistent with safety and good air 

pollution control practices for minimizing emissions. Determination of whether such operation and 

maintenance procedures are being used will be based on information available to the EPA 

Administrator which may include, but is not limited to, monitoring results, review of operation and 

maintenance procedures, review of operation and maintenance records, and inspection of the 

source. [40 CFR § 63.10000(b)]

b. If your coal-fired or solid oil derived fuel-fired EGU or IGCC EGU does not qualify as a LEE for 

total non-mercury HAP metals, individual non-mercury HAP metals, or filterable particulate matter 

(PM), you must demonstrate compliance through an initial performance test and you must 

monitor continuous performance through either use of a particulate matter continuous parametric 

monitoring system (PM CPMS), a PM CEMS, or, for an existing EGU, compliance performance 

testing repeated quarterly. [40 CFR § 63.10000(c)(1)(iv)]

c. If your EGU uses wet or dry flue gas desulfurization technology (this includes limestone injection 

into a fluidized bed combustion unit), you may apply a second alternative to HCl CEMS by 

installing and operating a sulfur dioxide (SO2) CEMS installed and operated in accordance with 

part 75 of this chapter to demonstrate compliance with the applicable SO2 emissions limit. [40 

CFR § 63.10000(c)(1)(v)]

d. If your coal-fired EGU does not qualify as a LEE for Hg, you must demonstrate initial and 

continuous compliance through use of a sorbent trap monitoring system, in accordance with 

appendix A to this subpart. [40 CFR § 63.10000(c)(1)(vi)]

(1) You may choose to use separate sorbent trap monitoring systems to comply with this 

subpart: One sorbent trap monitoring system to demonstrate compliance with the 

numeric mercury emissions limit during periods other than startup or shutdown and the 

other sorbent trap monitoring system to report average mercury concentration during 

startup periods or shutdown periods.

(2) You may choose to use one sorbent trap monitoring system to demonstrate compliance 

with the mercury emissions limit at all times (including startup periods and shutdown 

periods) and to report average mercury concentration. You must follow the startup or 

shutdown requirements that follow and as given in Table 3 to this subpart for each coalfired, liquid oil-fired, or solid oil-derived fuel-fired EGU.

e. If you demonstrate compliance with any applicable emissions limit through use of a continuous 

monitoring system (CMS), where a CMS includes a continuous parameter monitoring system 

(CPMS) as well as a continuous emissions monitoring system (CEMS), you must develop a sitespecific monitoring plan and submit this site-specific monitoring plan, if requested, at least 60 
Attachment C - Page 2 of 24

days before your initial performance evaluation (where applicable) of your CMS. This requirement 

also applies to you if you petition the Administrator for alternative monitoring parameters under 40 

CFR § 63.8(f). This requirement to develop and submit a site-specific monitoring plan does not 

apply to affected sources with existing monitoring plans that apply to CEMS and CPMS prepared 

under appendix B to part 60 or part 75 of this chapter, and that meet the requirements of 40 CFR 

§ 63.10010. Using the process described in 40 CFR § 63.8(f)(4), you may request approval of 

monitoring system quality assurance and quality control procedures alternative to those specified 

in 40 CFR § 63.10000(d)(1) and, if approved, include those in your site-specific monitoring plan. 

The monitoring plan must address the provisions in 40 CFR §§ 63.10000(d)(2) through (5). [40 

CFR § 63.10000(d)(1)]

f. If requested by the Administrator, you must submit the monitoring plan (or relevant portion of the 

plan) at least 60 days before the initial performance evaluation of a particular CMS, except where 

the CMS has already undergone a performance evaluation that meets the requirements of 40 

CFR § 63.10010 (e.g., if the CMS was previously certified under another program). [40 CFR §

63.10000(d)(3)]

g. You must operate and maintain the CMS according to the site-specific monitoring plan. [40 CFR §

63.10000(d)(4)]

h. The provisions of the site-specific monitoring plan must address the following items: [40 CFR §

63.10000(d)(5)]

(1) Installation of the CMS or sorbent trap monitoring system sampling probe or other 

interface at a measurement location relative to each affected process unit such that the 

measurement is representative of control of the exhaust emissions (e.g., on or 

downstream of the last control device). 

(2) Performance and equipment specifications for the sample interface, the pollutant 

concentration or parametric signal analyzer, and the data collection and reduction 

systems.

(3) Schedule for conducting initial and periodic performance evaluations.

(4) Performance evaluation procedures and acceptance criteria (e.g., calibrations), including 

the quality control program in accordance with the general requirements of 40 CFR § 

63.8(d).

(5) On-going operation and maintenance procedures, in accordance with the general 

requirements of 40 CFR §§ 63.8(c)(1)(ii), (c)(3), and (c)(4)(ii).

(6) Conditions that define a CMS that is out of control consistent with 40 CFR § 63.8(c)(7)(i) 

and for responding to out of control periods consistent with 40 CFR §§ 63.8(c)(7)(ii) and 

(c)(8).

(7) On-going recordkeeping and reporting procedures, in accordance with the general 

requirements of 40 CFR §§ 63.10(c), (e)(1), and (e)(2)(i), or as specifically required under 

Subpart UUUUU.

i. As part of your demonstration of continuous compliance, you must perform periodic tune-ups of 

your EGU(s), according to 40 CFR § 63.10021(e). [40 CFR § 63.10000(e)]
Attachment C - Page 3 of 24

II. TESTING AND INITIAL COMPLIANCE REQUIREMENTS

a. For each of your affected EGUs, you must demonstrate initial compliance with each applicable 

emissions limit through performance testing. Where two emissions limits are specified for a 

particular pollutant (e.g., a heat input-based limit in lb/MMBtu and an electrical output-based limit 

in lb/MWh), you may demonstrate compliance with either emission limit. For a particular 

compliance demonstration, you may be required to conduct one or more of the following activities 

in conjunction with performance testing: collection of hourly electrical load data (megawatts); 

establishment of operating limits according to 40 CFR § 63.10011 and Tables 4 and 7 to Subpart 

UUUUU; and CMS performance evaluations. In all cases, you must demonstrate initial 

compliance no later than the applicable date in 40 CFR § 63.10005(f) for tune-up work practices 

for existing EGUs, in 40 CFR § 63.9984 for other requirements for existing EGUs, and in 40 CFR 

§ 63.10005(g) for all requirements for new EGUs. [40 CFR § 63.10005(a)]

b. To demonstrate initial compliance using either a CMS that measures HAP concentrations directly 

(i.e., an Hg, HCl, or HF CEMS, or a sorbent trap monitoring system) or an SO2 or PM CEMS, the 

initial performance test consists of 30- (or, if emissions averaging for Hg is used, 90-) boiler 

operating days of data collected by the initial compliance demonstration date specified in 40 CFR 

§ 63.9984(f) with the certified monitoring system. Pollutant emission rates measured during 

startup periods and shutdown period (as defined in 40 CFR § 63.10042) are not to be included in 

the compliance demonstration, except as otherwise provided in 40 CFR § 63.10000(c)(1)(vi)(B) 

and 40 CFR § 63.10000(a)(2)(iii). [40 CFR § 63.10005(a)(2)]

(1) The 30- (or, if applicable, 90-) boiler operating day CMS performance test must 

demonstrate compliance with the applicable Hg, HCl, HF, PM, or SO2 emissions limit in 

Table 1 or 2 to 40 CFR 63, Subpart UUUUU.

(2) You must collect hourly data from auxiliary monitoring systems (i.e., stack gas flow rate, 

CO2, O2, or moisture, as applicable) during the performance test period, in order to 

convert the pollutant concentrations to units of the standard. If you choose to comply with 

an electrical output-based emission limit, you must also collect hourly electrical load data 

during the performance test period.

c. CMS requirements. If, for a particular emission or operating limit, you are required to (or elect to) 

demonstrate initial compliance using a continuous monitoring system, the CMS must pass a 

performance evaluation prior to the initial compliance demonstration. If a CMS has been 

previously certified under another state or federal program and is continuing to meet the on-going 

quality-assurance (QA) requirements of that program, then, provided that the certification and QA 

provisions of that program meet the applicable requirements of 40 CFR §§ 63.10010(b) through 

(h), an additional performance evaluation of the CMS is not required under this subpart. [40 CFR 

§ 63.10005(d)]

d. You may demonstrate initial compliance with the applicable SO2 emissions limit in Table 2 to this 

subpart through use of an SO2 CEMS installed and operated in accordance with part 75 of this 

chapter or appendix B to this subpart, as applicable. You may also demonstrate compliance with 

a filterable PM emission limit in Table 2 to this subpart through use of a PM CEMS installed, 

certified, and operated in accordance with 40 CFR § 63.10010(i). Initial compliance is achieved if 

the arithmetic average of 30-boiler operating days of quality-assured CEMS data, expressed in 

units of the standard (see 40 CFR § 63.10007(e)), meets the applicable SO2 or PM emissions 

limit in Table 2 to this subpart. Use Equation 19-19 of Method 19 in appendix A-7 to part 60 of this 

chapter to calculate the 30-boiler operating day average emissions rate. [40 CFR §

63.10005(d)(1)]
Attachment C - Page 4 of 24

e. For affected EGUs that are either required to or elect to demonstrate initial compliance with the 

applicable Hg emission limit in Table 2 of this subpart using sorbent trap monitoring systems, 

initial compliance must be demonstrated no later than the applicable date specified in 40 CFR §

63.9984(f) for existing EGUs. Initial compliance is achieved if the arithmetic average of 30-boiler 

operating days of quality-assured sorbent trap monitoring system data, expressed in units of the 

standard (see section 6.2 of appendix A to this subpart), meets the applicable Hg emission limit in 

Table 2 to this subpart. [40 CFR § 63.10005(d)(3)]

f. All affected EGUs are subject to the work practice standards in Table 3 of 40 CFR Part 63, 

Subpart UUUUU. As part of your initial compliance demonstration, you must conduct a 

performance tune-up of your EGU according to 40 CFR § 63.10021(e). [40 CFR § 63.10005(e)]

g. For existing affected sources a tune-up may occur prior to April 16, 2012, so that existing sources 

employing neural network combustion controls, up to 54 calendar months (48 months from 

promulgation plus 180 days) after the date that is specified for your source in 40 CFR § 63.9984 

and according to the applicable provisions in 40 CFR § 63.7(a)(2) as cited in Table 9 to this 

subpart to demonstrate compliance with this requirement. If a tune-up occurs prior to such date, 

the source must maintain adequate records to show that the tune-up met the requirements of this 

standard. [40 CFR § 63.10005(f)]

h. You must follow the startup and shutdown requirements given in Table 3 of 40 CFR Part 63, 

Subpart UUUUU. [40 CFR § 63.10005(j)]

i. You must submit a Notification of Compliance Status summarizing the results of your initial 

compliance demonstration, as provided in 40 CFR § 63.10030. [40 CFR § 63.10005(k)]

Subsequent performance tests and tune-ups

j. If you are required to meet an applicable tune-up work practice standard, you must conduct a 

performance tune-up according to 40 CFR § 63.10021(e). For EGUs employing neural network 

combustion optimization systems during normal operation, each performance tune-up specified in 

40 CFR § 63.10021(e) must be no more than 48 calendar months after the previous performance 

tune-up. [40 CFR § 63.10006(i)(2)]

k. You must report the results of performance tests and performance tune-ups within 60 days after 

the completion of the performance tests and performance tune-ups. The reports for all 

subsequent performance tests must include all applicable information required in 40 CFR §

63.10031. [40 CFR § 63.10006(j)]

Methods and other procedures for the performance tests

l. Except as otherwise provided in this section, you must conduct all required performance tests 

according to 40 CFR §§ 63.7(d), (e), (f), and (h). You must also develop a site-specific test plan 

according to the requirements in 40 CFR § 63.7(c). [40 CFR § 63.10007(a)]

m. If you use CEMS (Hg, HCl, SO2, or other) to determine compliance with a 30- (or, if applicable, 

90-) boiler operating day rolling average emission limit, you must collect quality- assured CEMS 

data for all unit operating conditions, including startup and shutdown (see 40 CFR § 63.10011(g) 

and Table 3 to 40 CFR 63, Subpart UUUUU), except as otherwise provided in 40 CFR §

63.10020(b). Emission rates determined during startup periods and shutdown periods (as defined 

in 40 CFR § 63.10042) are not to be included in the compliance determinations, except as 

otherwise provided in 40 CFR §§ 63.10000(c)(1)(vi)(B) and 63.10005(a)(2)(iii). [40 CFR §

63.10007(a)(1)]
Attachment C - Page 5 of 24

n. You must conduct each performance test (including traditional 3-run stack tests, 30-boiler 

operating day tests based on CEMS data (or sorbent trap monitoring system data), and 30-boiler 

operating day Hg emission tests for LEE qualification) according to the requirements in Table 5 to 

Subpart UUUUU. [40 CFR § 63.10007(b)]

o. To use the results of performance testing to determine compliance with the applicable emission 

limits in Table 2 to Subpart UUUUU, proceed as follows: [40 CFR § 63.10007(e)]

(1) Except for a 30-boiler operating day performance test based on CEMS (or sorbent trap 

monitoring system) data, if measurement results for any pollutant are reported as below 

the method detection level (e.g., laboratory analytical results for one or more sample 

components are below the method defined analytical detection level), you must use the 

method detection level as the measured emissions level for that pollutant in calculating 

compliance. The measured result for a multiple component analysis (e.g., analytical 

values for multiple Method 29 fractions both for individual HAP metals and for total HAP 

metals) may include a combination of method detection level data and analytical data 

reported above the method detection level.

(2) If the limits are expressed in lb/MMBtu or lb/TBtu, you must use the F-factor methodology 

and equations in sections 12.2 and 12.3 of EPA Method 19 in appendix A-7 to part 60 of 

this chapter. In cases where an appropriate F-factor is not listed in Table 19-2 of Method 

19, you may use F-factors from Table 1 in section 3.3.5 of appendix F to part 75 of this 

chapter, or F-factors derived using the procedures in section 3.3.6 of appendix to part 75 

of this chapter. Use the following factors to convert the pollutant concentrations 

measured during the initial performance tests to units of lb/scf, for use in the applicable 

Method 19 equations:

(i) Multiply SO2 ppm by 1.66 × 10−7;

(ii) Multiply Hg concentrations (μg/scm) by 6.24 × 10−11.

(3) To determine compliance with emission limits expressed in lb/MWh or lb/GWh, you must 

first calculate the pollutant mass emission rate during the performance test, in units of 

lb/h. For Hg, if a CEMS or sorbent trap monitoring system is used, use Equation A-2 or A3 in appendix A to this subpart (as applicable). In all other cases, use an equation that 

has the general form of Equation A-2 or A-3, replacing the value of K with 1.66 × 10−7

lb/scf-ppm for SO2, 9.43 × 10−8lb/scf-ppm for HCl (if an HCl CEMS is used), 5.18 × 10−8

lb/scf-ppm for HF (if an HF CEMS is used), or 6.24 × 10−8lb-scm/mg-scf for HAP metals 

and for HCl and HF (when performance stack testing is used), and defining Ch as the 

average SO2, HCl, or HF concentration in ppm, or the average HAP metals concentration 

in mg/dscm. This calculation requires stack gas volumetric flow rate (scfh) and (in some 

cases) moisture content data (see 40 CFR §§ 63.10005(h)(3) and 63.10010). Then, if the 

applicable emission limit is in units of lb/GWh, use Equation A-4 in appendix A to this 

subpart to calculate the pollutant emission rate in lb/GWh. In this calculation, define (M)h

as the calculated pollutant mass emission rate for the performance test (lb/h), and define 

(MW)h as the average electrical load during the performance test (megawatts). If the 

applicable emission limit is in lb/MWh rather than lb/GWh, omit the 103term from 

Equation A-4 to determine the pollutant emission rate in lb/MWh.

p. If you elect to (or are required to) use CEMS to continuously monitor Hg, HCl, HF, SO2, or PM 

emissions (or, if applicable, sorbent trap monitoring systems to continuously collect Hg emissions 

data), the following default values are available for use in the emission rate calculations during 

startup periods or shutdown periods (as defined in 40 CFR § 63.10042). For the purposes of this 

subpart, these default values are not considered to be substitute data. [40 CFR § 63.10007(f)]
Attachment C - Page 6 of 24

(1) Diluent cap values. If you use CEMS (or, if applicable, sorbent trap monitoring systems) 

to comply with a heat input-based emission rate limit, you may use the following diluent 

cap values for a startup or shutdown hour in which the measured CO2 concentration is 

below the cap value or the measured O2 concentration is above the cap value:

(i) For an IGCC EGU, you may use 1% for CO2 or 19% for O2.

(ii) For all other EGUs, you may use 5% for CO2 or 14% for O2.

(2) Default electrical load. If you use CEMS to continuously monitor Hg, HCl, HF, SO2, or PM 

emissions (or, if applicable, sorbent trap monitoring systems to continuously collect Hg 

emissions data), the following default value is available for use in the emission rate 

calculations during startup periods or shutdown periods (as defined in 40 CFR §

63.10042). For the purposes of this subpart, this default value is not considered to be 

substitute data. For a startup or shutdown hour in which there is heat input to an affected 

EGU but zero electrical load, you must calculate the pollutant emission rate using a value 

equivalent to 5% of the maximum sustainable electrical output, expressed in megawatts, 

as defined in section 6.5.2.1(a)(1) of Appendix A to 40 CFR Part 75. This default 

electrical load is either the nameplate capacity of the EGU or the highest electrical load 

observed in at least four representative quarters of EGU operation. For a monitored 

common stack, the default electrical load is used only when all EGUs are operating (i.e., 

combusting fuel) are in startup or shutdown mode, and have zero electrical generation. 

Under those conditions, a default electrical load equal to 5% of the combined maximum 

sustainable electrical load of the EGUs that are operating but have a total of zero 

electrical load must be used to calculate the hourly electrical output-based pollutant 

emissions rate.

q. Upon request, you shall make available to the EPA Administrator such records as may be 

necessary to determine whether the performance tests have been done according to the 

requirements of 40 CFR § 63.10007. [40 CFR § 63.10007(g)]

r. You may use emissions averaging method as described in 40 CFR § 63.10009 to demonstrate 

compliance with the filterable PM, SO2, or Hg emission limits. [40 CFR § 63.10009]

s. You must comply with the applicable monitoring, installation, operation, and maintenance 

requirements specified in 40 CFR § 63.10010 for CEMS. [40 CFR § 63.10010]

t. You must demonstrate initial compliance with each emissions limit that applies to you by

conducting performance testing. [40 CFR § 63.10011(a)]

u. If you use CEMS or sorbent trap monitoring systems to measure a HAP (e.g., Hg or HCl) directly, 

the first 30-boiler operating day (or, if alternate emissions averaging is used for Hg, the 90-boiler 

operating day) rolling average emission rate obtained with certified CEMS after the applicable 

date in §63.9984 (or, if applicable, prior to that date, as described in 40 CFR § 63.10005(b)(2)), 

expressed in units of the standard, is the initial performance test. Initial compliance is 

demonstrated if the results of the performance test meet the applicable emission limit in Table 2 

to this subpart. [40 CFR § 63.10011(c)(1)]

v. For a unit that uses a CEMS to measure SO2 or PM emissions for initial compliance, the first 30 

boiler operating day average emission rate obtained with certified CEMS after the applicable date 

in 40 CFR § 63.9984 (or, if applicable, prior to that date, as described in 40 CFR §

63.10005(b)(2)), expressed in units of the standard, is the initial performance test. Initial 

compliance is demonstrated if the results of the performance test meet the applicable SO2 or 
Attachment C - Page 7 of 24

filterable PM emission limit in Table 2 to 40 CFR Part 63, Subpart UUUUUU. [40 CFR § 

63.10011(c)(2)]

w. You must submit a Notification of Compliance Status containing the results of the initial 

compliance demonstration, according to 40 CFR § 63.10030(e). [40 CFR § 63.10011(e)]

x. You must determine the fuel whose combustion produces the least uncontrolled emissions, i.e., 

the cleanest fuel, either natural gas or distillate oil, that is available on site or accessible nearby 

for use during periods of startup or shutdown. [40 CFR § 63.10011(f)(1)]

y. Your cleanest fuel, either natural gas or distillate oil, for use during periods of startup or shutdown 

determination may take safety considerations into account. [40 CFR § 63.10011(f)(2)]

z. You must follow the startup or shutdown requirements as given in Table 3 to subpart UUUUU for 

each coal-fired EGU. [40 CFR § 63.10011(g)]

(1) You may use the diluent cap and default electrical load values, as described in 40 CFR §

63.10007(f), during startup periods or shutdown periods.

(2) You must operate all CMS, collect data, calculate pollutant emission rates, and record 

data during startup periods or shutdown periods.

(3) You must report the information as required in 40 CFR § 63.10031.

(4) If you choose to use paragraph (2) of the definition of “startup” in 40 CFR § 63.10042 and 

you find that you are unable to safely engage and operate your particulate matter (PM) 

control(s) within 1 hour of first firing of coal, you may choose to rely on paragraph (1) of 

definition of “startup” in 40 CFR § 63.10042 or you may submit a request to use an 

alternative non-opacity emissions standard, as described below.

(i) As mentioned in 40 CFR § 63.6(g)(1), the request will be published in the Federal 

Register for notice and comment rulemaking. Until promulgation in the Federal 

Register of the final alternative non-opacity emission standard, you shall comply 

with paragraph (1) of the definition of “startup” in 40 CFR § 63.10042. You shall 

not implement the alternative non-opacity emissions standard until promulgation 

in the Federal Register of the final alternative non-opacity emission standard.

(ii) The request need not address the items contained in 40 CFR § 63.6(g)(2).

(iii) The request shall provide evidence of a documented manufacturer-identified 

safely issue.

(iv) The request shall provide information to document that the PM control device is 

adequately designed and sized to meet the PM emission limit applicable to the 

EGU.

(v) In addition, the request shall contain documentation that:

(A) The EGU is using clean fuels to the maximum extent possible to bring 

the EGU and PM control device up to the temperature necessary to 

alleviate or prevent the identified safety issues prior to the combustion of 

primary fuel in the EGU;
Attachment C - Page 8 of 24

(B) The EGU has explicitly followed the manufacturer's procedures to 

alleviate or prevent the identified safety issue; and

(C) Identifies with specificity the details of the manufacturer's statement of 

concern.

(vi) The request shall specify the other work practice standards the EGU owner or 

operator will take to limit HAP emissions during startup periods and shutdown 

periods to ensure a control level consistent with the work practice standards of 

the final rule.

(vii) You must comply with all other work practice requirements, including but not 

limited to data collection, recordkeeping, and reporting requirements.

III. CONTINUOUS COMPLIANCE REQUIREMENTS

General compliance requirements

a. You must monitor and collect data according to this section and the site-specific monitoring plan 

required by 40 CFR § 63.10000(d). [40 CFR § 63.10020(a)]

b. You must operate the monitoring system and collect data at all required intervals at all times that 

the affected EGU is operating, except for periods of monitoring system malfunctions or out-ofcontrol periods (see 40 CFR § 63.8(c)(7) of this part), and required monitoring system quality 

assurance or quality control activities, including, as applicable, calibration checks and required 

zero and span adjustments. You are required to affect monitoring system repairs in response to 

monitoring system malfunctions and to return the monitoring system to operation as expeditiously 

as practicable. [40 CFR § 63.10020(b)]

c. You may not use data recorded during EGU startup or shutdown in calculations used to report 

emissions, except as otherwise provided in 40 CFR §§ 63.10000(c)(1)(vi)(B) and 

63.10005(a)(2)(iii). In addition, data recorded during monitoring system malfunctions or 

monitoring system out-of-control periods, repairs associated with monitoring system malfunctions 

or monitoring system out-of-control periods, or required monitoring system quality assurance or 

control activities may not be used in calculations used to report emissions or operating levels. 

You must use all of the quality-assured data collected during all other periods in assessing the 

operation of the control device and associated control system. [40 CFR § 63.10020(c)]

d. Except for periods of monitoring system malfunctions or monitoring system out-of-control periods, 

repairs associated with monitoring system malfunctions or monitoring system out-of-control 

periods, and required monitoring system quality assurance or quality control activities including, 

as applicable, calibration checks and required zero and span adjustments), failure to collect 

required data is a deviation from the monitoring requirements. [40 CFR § 63.10020(d)]

e. During each period of startup, you must record the following for each EGU: [40 CFR §

63.10020(e)(1)]

(1) The date and time that clean fuels being combusted for the purpose of startup begins;

(2) The quantity and heat input of clean fuel for each hour of startup;

(3) The electrical load for each hour of startup;
Attachment C - Page 9 of 24

(4) The date and time that non-clean fuel combustion begins; and

(5) The date and time that clean fuels being combusted for the purpose of startup ends.

f. During each period of shutdown, you must record the following for each EGU: [40 CFR §

63.10020(e)(2)]

(1) The date and time that clean fuels being combusted for the purpose of shutdown begins;

(2) The quantity and heat input of clean fuel for each hour of shutdown;

(3) The electrical load for each hour of shutdown;

(4) The date and time that non-clean fuel combustion ends; and

(5) The date and time that clean fuels being combusted for the purpose of shutdown ends.

g. For PM or non-mercury HAP metals work practice monitoring during startup periods, you must 

monitor and collect data according to 40 CFR § 63.10020 and the site-specific monitoring plan 

required by 40 CFR § 63.10011(l). [40 CFR § 63.10020(e)(3)]

Continuous compliance with the emission limitations, operating limits, and work practice 

standards

h. You must demonstrate continuous compliance with each emissions limit, operating limit, and work 

practice standard according to the monitoring specified in Table 7 to Subpart UUUUU and 40 

CFR § 63.10021(b) through (g). [40 CFR § 63.10021(a)]

i. Except as otherwise provided in 40 CFR § 63.10020(c), if you use a CEMS to measure SO2, PM, 

HCl, HF, or Hg emissions, or using a sorbent trap monitoring system to measure Hg emissions, 

you must demonstrate continuous compliance by using all quality-assured hourly data recorded 

by the CEMS (or sorbent trap monitoring system) and the other required monitoring systems 

(e.g., flow rate, CO2, O2, or moisture systems) to calculate the arithmetic average emissions rate 

in units of the standard on a continuous 30-boiler operating day (or, if alternate emissions 

averaging is used for Hg, 90-boiler operating day) rolling average basis, updated at the end of 

each new boiler operating day. Use Equation 8 to determine the 30- (or, if applicable, 90-) boiler 

operating day rolling average. [40 CFR § 63.10021(b)]

Where:

Heri is the hourly emissions rate for hour i and n is the number of hourly emissions rate values collected over 

30- (or, if applicable, 90-) boiler operating days.

j. If you must conduct periodic performance tune-ups of your EGU(s) as specified below and

perform the first tune-up as part of your initial compliance demonstration. Notwithstanding this 

requirement, you may delay the first burner inspection until the next scheduled unit outage 

provided you meet the requirements of 40 CFR § 63.10005. Subsequently, you must perform an 

inspection of the burner at least once every 36 calendar months unless your EGU employs neural 

network combustion optimization during normal operations in which case you must perform an 
Attachment C - Page 10 of 24

inspection of the burner and combustion controls at least once every 48 calendar months. [40 

CFR § 63.10021(e)]

(1) As applicable, inspect the burner and combustion controls, and clean or replace any 

components of the burner or combustion controls as necessary upon initiation of the work 

practice program and at least once every required inspection period. Repair of a burner 

or combustion control component requiring special order parts may be scheduled as 

follows:

(i) Burner or combustion control component parts needing replacement that affect 

the ability to optimize NOX and CO must be installed within 3 calendar months 

after the burner inspection,

(ii) Burner or combustion control component parts that do not affect the ability to 

optimize NOX and CO may be installed on a schedule determined by the 

operator;

(2) As applicable, inspect the flame pattern and make any adjustments to the burner or 

combustion controls necessary to optimize the flame pattern. The adjustment should be 

consistent with the manufacturer's specifications, if available, or in accordance with best 

combustion engineering practice for that burner type;

(3) As applicable, observe the damper operations as a function of mill and/or cyclone 

loadings, cyclone and pulverizer coal feeder loadings, or other pulverizer and coal mill 

performance parameters, making adjustments and effecting repair to dampers, controls, 

mills, pulverizers, cyclones, and sensors;

(4) As applicable, evaluate windbox pressures and air proportions, making adjustments and 

effecting repair to dampers, actuators, controls, and sensors;

(5) Inspect the system controlling the air-to-fuel ratio and ensure that it is correctly calibrated 

and functioning properly. Such inspection may include calibrating excess O2 probes 

and/or sensors, adjusting overfire air systems, changing software parameters, and 

calibrating associated actuators and dampers to ensure that the systems are operated as 

designed. Any component out of calibration, in or near failure, or in a state that is likely to 

negate combustion optimization efforts prior to the next tune-up, should be corrected or 

repaired as necessary;

(6) Optimize combustion to minimize generation of CO and NOX. This optimization should be 

consistent with the manufacturer's specifications, if available, or best combustion 

engineering practice for the applicable burner type. NOX optimization includes burners, 

overfire air controls, concentric firing system improvements, neural network or 

combustion efficiency software, control systems calibrations, adjusting combustion zone 

temperature profiles, and add-on controls such as SCR and SNCR; CO optimization 

includes burners, overfire air controls, concentric firing system improvements, neural 

network or combustion efficiency software, control systems calibrations, and adjusting 

combustion zone temperature profiles;

(7) While operating at full load or the predominantly operated load, measure the 

concentration in the effluent stream of CO and NOX in ppm, by volume, and oxygen in 

volume percent, before and after the tune-up adjustments are made (measurements may 

be either on a dry or wet basis, as long as it is the same basis before and after the 

adjustments are made). You may use portable CO, NOX and O2 monitors for this 

measurement. EGU's employing neural network optimization systems need only provide 
Attachment C - Page 11 of 24

a single pre- and post-tune-up value rather than continual values before and after each 

optimization adjustment made by the system;

(8) Maintain on-site and submit, if requested by the Administrator, an annual report 

containing the information in 40 CFR § 63.10021(e)(1) through (e)(9) including:

(i) The concentrations of CO and NOX in the effluent stream in ppm by volume, and 

oxygen in volume percent, measured before and after an adjustment of the EGU 

combustion systems;

(ii) A description of any corrective actions taken as a part of the combustion 

adjustment; and

(iii) The type(s) and amount(s) of fuel used over the 12 calendar months prior to an 

adjustment, but only if the unit was physically and legally capable of using more 

than one type of fuel during that period; and

(9) Report the dates of the initial and subsequent tune-ups as follows:

(i) If the first required tune-up is performed as part of the initial compliance 

demonstration, report the date of the tune-up in hard copy (as specified in 40 

CFR § 63.10030) and electronically (as specified in 40 CFR § 63.10031). Report 

the date of each subsequent tune-up electronically (as specified in 40 CFR § 

63.10031).

(ii) If the first tune-up is not conducted as part of the initial compliance 

demonstration, but is postponed until the next unit outage, report the date of that 

tune-up and all subsequent tune-ups electronically, in accordance with 40 CFR § 

63.10031.

k. You must submit the reports required under 40 CFR § 63.10031 and, if applicable, the reports 

required under appendices A and B to Subpart UUUUU. The electronic reports required by 

appendices A and B to Subpart UUUUU must be sent to the Administrator electronically in a 

format prescribed by the Administrator, as provided in 40 CFR § 63.10031. CEMS data (except 

for PM CEMS and any approved alternative monitoring using a HAP metals CEMS) shall be 

submitted using EPA's Emissions Collection and Monitoring Plan System (ECMPS) Client Tool. 

Other data, including PM CEMS data, HAP metals CEMS data, and CEMS performance test 

detail reports, shall be submitted in the file format generated through use of EPA's Electronic 

Reporting Tool, the Compliance and Emissions Data Reporting Interface, or alternate electronic 

file format, all as provided for under 40 CFR § 63.10031. [40 CFR § 63.10021(f)]

l. You must report each instance in which you did not meet an applicable emissions limit or 

operating limit or failed to conduct a required tune-up. These instances are deviations from the 

requirements of Subpart UUUUU. These deviations must be reported according to 40 CFR § 

63.10031. [40 CFR § 63.10021(g)]

m. You must follow the startup or shutdown requirements as given in Table 3 to subpart UUUUU. [40 

CFR § 63.10021(h)]

(1) You may use the diluent cap and default electrical load values, as described in 40 CFR §

63.10007(f), during startup periods or shutdown periods.
Attachment C - Page 12 of 24

(2) You must operate all CMS, collect data, calculate pollutant emission rates, and record 

data during startup periods or shutdown periods.

(3) You must report the information as required in 40 CFR § 63.10031.

(4) You may choose to submit an alternative non-opacity emission standard, in accordance 

with the requirements contained in 40 CFR § 63.10011(g)(4). Until promulgation in the 

Federal Register of the final alternative non-opacity emission standard, you shall comply 

with paragraph (1) of the definition of “startup” in 40 CFR § 63.10042.

n. You must provide reports as specified in 40 CFR § 63.10031 concerning activities and periods of 

startup and shutdown. [40 CFR § 63.10021(i)]

Demonstrate continuous compliance under the emissions averaging provision

o. If the permittee elects to demonstrate compliance under the emissions averaging provision, the 

permittee must demonstrate compliance with this subpart on a continuous basis by meeting the 

requirements of 40 CFR §§ 63.1022(a)(1), (a)(4), and (b). [40 CFR § 63.10022]

IV. NOTIFICATION, REPORTS, AND RECORDS

Notifications Requirements

a. You must submit all of the notifications in §40 CFR § 63.7(b) and (c), 63.8 (e), (f)(4) and (6), and 

63.9 (b) through (h) that apply to you by the dates specified. [40 CFR § 63.10030(a)]

b. When you are required to conduct a performance test, you must submit a Notification of Intent to 

conduct a performance test at least 30 days before the performance test is scheduled to begin.

[40 CFR § 63.10030(d)]

c. When you are required to conduct an initial compliance demonstration as specified in 40 CFR §

63.10011(a), you must submit a Notification of Compliance Status according to 40 CFR §

63.9(h)(2)(ii). The Notification of Compliance Status report must contain all the information 

specified in 40 CFR § 63.10030(e)(1) through (8), as applicable. [40 CFR § 63.10030(e)]

(1) A description of the affected source(s) including identification of which subcategory the 

source is in, the design capacity of the source, a description of the add-on controls used 

on the source, description of the fuel(s) burned, including whether the fuel(s) were 

determined by you or EPA through a petition process to be a non-waste under 40 CFR 

241.3, whether the fuel(s) were processed from discarded non-hazardous secondary 

materials within the meaning of 40 CFR 241.3, and justification for the selection of fuel(s) 

burned during the performance test.

(2) Summary of the results of all performance tests and fuel analyses and calculations 

conducted to demonstrate initial compliance including all established operating limits.

(3) Identification of whether you plan to demonstrate compliance with each applicable 

emission limit through performance testing; fuel moisture analyses; performance testing 

with operating limits (e.g., use of PM CPMS); CEMS; or a sorbent trap monitoring 

system.

(4) Identification of whether you plan to demonstrate compliance by emissions averaging.
Attachment C - Page 13 of 24

(5) A signed certification that you have met all applicable emission limits and work practice 

standards.

(6) If you had a deviation from any emission limit, work practice standard, or operating limit, 

you must also submit a brief description of the deviation, the duration of the deviation, 

emissions point identification, and the cause of the deviation in the Notification of 

Compliance Status report.

(7) In addition to the information required in 40 CFR § 63.9(h)(2), your notification of 

compliance status must include the following:

(i) A summary of the results of the annual performance tests and documentation of 

any operating limits that were reestablished during this test, if applicable. If you 

are conducting stack tests once every 3 years consistent with 40 CFR § 

63.10006(b), the date of the last three stack tests, a comparison of the emission 

level you achieved in the last three stack tests to the 50 percent emission limit 

threshold required in 40 CFR § 63.10006(i), and a statement as to whether there 

have been any operational changes since the last stack test that could increase 

emissions.

(ii) Certifications of compliance, as applicable, and must be signed by a responsible 

official stating:

(A) “This EGU complies with the requirements in 40 CFR § 63.10021(a) to 

demonstrate continuous compliance.” and

(B) “No secondary materials that are solid waste were combusted in any

affected unit.”

(8) Identification of whether you plan to rely on paragraph (1) or (2) of the definition of 

“startup” in 40 CFR § 63.10042.

(i) Should you choose to rely on paragraph (2) of the definition of “startup” in 40 

CFR § 63.10042 for your EGU, you shall include a report that identifies:

(A) The original EGU installation date;

(B) The original EGU design characteristics, including, but not limited to, fuel 

and PM controls;

(C) Each design PM control device efficiency;

(D) The design PM emission rate from the EGU in terms of pounds PM per 

MMBtu and pounds PM per hour;

(E) The design time from start of fuel combustion to necessary conditions for 

each PM control device startup;

(F) Each design PM control device efficiency upon startup of the PM control 

device;

(G) The design EGU uncontrolled PM emission rate in terms of pounds PM 

per hour;
Attachment C - Page 14 of 24

(H) Each change from the original design that did or could have changed PM 

emissions, including, but not limited to, each different fuel mix, each 

revision to each PM control device, and each EGU revision, along with 

the month and year that the change occurred;

(I) Current EGU PM producing characteristics, including, but not limited to, 

fuel mix and PM controls;

(J) Current PM emission rate from the EGU in terms of pounds PM per 

MMBtu and pounds per hour;

(K) Current PM control device efficiency from each PM control device;

(L) Current time from start of fuel combustion to conditions necessary for 

each PM control device startup;

(M) Current PM control device efficiency upon startup of each PM control 

device; and

(N) Current EGU uncontrolled PM emission rate in terms of pounds PM per 

hour.

(ii) The report shall be prepared, signed, and sealed by a professional engineer 

licensed in the state where your EGU is located. Apart from preparing, signing, 

and sealing this report, the professional engineer shall be independent and not 

otherwise employed by your company, any parent company of your company, or 

any subsidiary of your company.

Reporting Requirements

d. You must submit each report in Table 8 to Subpart UUUUU that applies to you. If you are 

required to (or elect to) continuously monitor Hg and/or HCl and/or HF emissions, you must also 

submit the electronic reports required under appendix A and/or appendix B to the subpart, at the 

specified frequency. [40 CFR § 63.10031(a)]

e. Unless the Administrator has approved a different schedule for submission of reports under 40 

CFR § 63.10(a), you must submit each report by the date in Table 8 to Subpart UUUUU and 

according to the requirements specified below: [40 CFR § 63.10031(b)]

(1) The first compliance report must cover the period beginning on the compliance date that 

is specified for your affected source in 40 CFR § 63.9984 and ending on June 30 or 

December 31, whichever date is the first date that occurs at least 180 days after the 

compliance date that is specified for your source in 40 CFR § 63.9984.

(2) The first compliance report must be postmarked or submitted electronically no later than 

July 31 or January 31, whichever date is the first date following the end of the first 

calendar half after the compliance date that is specified for your source in 40 CFR § 

63.9984.

(3) Each subsequent compliance report must cover the semiannual reporting period from 

January 1 through June 30 or the semiannual reporting period from July 1 through 

December 31.
Attachment C - Page 15 of 24

(4) Each subsequent compliance report must be postmarked or submitted electronically no 

later than July 31 or January 31, whichever date is the first date following the end of the 

semiannual reporting period.

(5) If the permitting authority has established dates for submitting semiannual reports 

pursuant to 40 CFR 70.6(a)(3)(iii)(A) or 40 CFR 71.6(a)(3)(iii)(A), you may submit the first 

and subsequent compliance reports according to the dates the permitting authority has 

established. 

f. The compliance report must contain the information specified as follows: [40 CFR § 63.10031(c)]

(1) The information required by the summary report located in 40 CFR § 63.10(e)(3)(vi).

(2) The total fuel use by each affected source subject to an emission limit, for each calendar 

month within the semiannual reporting period, including, but not limited to, a description 

of the fuel, whether the fuel has received a non-waste determination by EPA or your 

basis for concluding that the fuel is not a waste, and the total fuel usage amount with 

units of measure.

(3) Indicate whether you burned new types of fuel during the reporting period. If you did burn 

new types of fuel you must include the date of the performance test where that fuel was 

in use.

(4) Include the date of the most recent tune-up for each unit subject to the requirement to 

conduct a performance tune-up according to 40 CFR § 63.10021(e). Include the date of 

the most recent burner inspection if it was not done every 36 (or 48) months and was 

delayed until the next scheduled unit shutdown.

(5) For each instance of startup or shutdown:

(i) Include the maximum clean fuel storage capacity and the maximum hourly heat 

input that can be provided for each clean fuel determined according to the 

requirements of 40 CFR § 63.10032(f).

(ii) Include the information required to be monitored, collected, or recorded 

according to the requirements of 40 CFR § 63.10020(e).

(iii) If you choose to use CEMS for compliance purposes, include hourly average 

CEMS values and hourly average flow rates. Use units of milligrams per cubic 

meter for PM CEMS, micrograms per cubic meter for Hg CEMS, and ppmv for 

HCl, HF, or SO2 CEMS. Use units of standard cubic meters per hour on a wet 

basis for flow rates.

(iv) If you choose to use a separate sorbent trap measurement system for startup or 

shutdown reporting periods, include hourly average mercury concentration in 

terms of micrograms per cubic meter.

(v) If you choose to use a PM CPMS, include hourly average operating parameter 

values in terms of the operating limit, as well as the operating parameter to PM 

correlation equation.

g. For each excess emissions occurring at an affected source where you are using a CMS to 

comply with that emission limit or operating limit, you must include the information required in 40 
Attachment C - Page 16 of 24

CFR § 63.10(e)(3)(v) in the compliance report specified 40 CFR § 63.10031(c). [40 CFR §

63.10031(d)]

h. You must report all deviations as defined in Subpart UUUUU in the semiannual monitoring report 

required by 40 CFR 70.6(a)(3)(iii)(A) or 40 CFR 71.6(a)(3)(iii)(A). If an affected source submits a 

compliance report pursuant to Table 8 to Subpart UUUUU along with, or as part of, the 

semiannual monitoring report required by 40 CFR 70.6(a)(3)(iii)(A) or 40 CFR 71.6(a)(3)(iii)(A), 

and the compliance report includes all required information concerning deviations from any 

emission limit, operating limit, or work practice requirement in Subpart UUUUU, submission of the 

compliance report satisfies any obligation to report the same deviations in the semiannual 

monitoring report. Submission of a compliance report does not otherwise affect any obligation the 

affected source may have to report deviations from permit requirements to the permit authority.

[40 CFR § 63.10031(e)]

i. On or after April 16, 2017, within 60 days after the date of completing each performance test, you 

must submit the performance test reports required by this subpart to EPA's WebFIRE database 

by using the Compliance and Emissions Data Reporting Interface (CEDRI) that is accessed 

through EPA's Central Data Exchange (CDX) (www.epa.gov/cdx). Performance test data must be 

submitted in the file format generated through use of EPA's Electronic Reporting Tool (ERT) (see 

http://www.epa.gov/ttn/chief/ert/index.html). Only data collected using those test methods on the 

ERT Web site are subject to this requirement for submitting reports electronically to WebFIRE. 

Owners or operators who claim that some of the information being submitted for performance 

tests is confidential business information (CBI) must submit a complete ERT file including 

information claimed to be CBI on a compact disk or other commonly used electronic storage 

media (including, but not limited to, flash drives) to EPA. The electronic media must be clearly 

marked as CBI and mailed to U.S. EPA/OAPQS/CORE CBI Office, Attention: WebFIRE 

Administrator, MD C404-02, 4930 Old Page Rd., Durham, NC 27703. The same ERT file with the 

CBI omitted must be submitted to EPA via CDX as described earlier in this paragraph. At the 

discretion of the delegated authority, you must also submit these reports, including the 

confidential business information, to the delegated authority in the format specified by the 

delegated authority. [40 CFR § 63.10031(f)]

(1) On or after April 16, 2017, within 60 days after the date of completing each CEMS (SO2, 

PM, HCl, HF, and Hg) performance evaluation test, as defined in 40 CFR § 63.2 and 

required by this subpart, you must submit the relative accuracy test audit (RATA) data 

(or, for PM CEMS, RCA and RRA data) required by this subpart to EPA's WebFIRE 

database by using CEDRI that is accessed through EPA's CDX (www.epa.gov/cdx). The 

RATA data shall be submitted in the file format generated through use of EPA's 

Electronic Reporting Tool (ERT) (http://www.epa.gov/ttn/chief/ert/index.html). Only RATA 

data compounds listed on the ERT Web site are subject to this requirement. Owners or 

operators who claim that some of the information being submitted for RATAs is 

confidential business information (CBI) shall submit a complete ERT file including 

information claimed to be CBI on a compact disk or other commonly used electronic 

storage media (including, but not limited to, flash drives) by registered letter to EPA and 

the same ERT file with the CBI omitted to EPA via CDX as described earlier in this 

paragraph. The compact disk or other commonly used electronic storage media shall be 

clearly marked as CBI and mailed to U.S. EPA/OAPQS/CORE CBI Office, Attention: 

WebFIRE Administrator, MD C404-02, 4930 Old Page Rd., Durham, NC 27703. At the 

discretion of the delegated authority, owners or operators shall also submit these RATAs 

to the delegated authority in the format specified by the delegated authority. Owners or 

operators shall submit calibration error testing, drift checks, and other information 

required in the performance evaluation as described in 40 CFR § 63.2 and as required in 

this chapter.
Attachment C - Page 17 of 24

(2) On or after April 16, 2017, for a PM CEMS, PM CPMS, or approved alternative 

monitoring using a HAP metals CEMS, within 60 days after the reporting periods ending 

on March 31st, June 30th, September 30th, and December 31st, you must submit 

quarterly reports to EPA's WebFIRE database by using the CEDRI that is accessed 

through EPA's CDX (www.epa.gov/cdx). You must use the appropriate electronic 

reporting form in CEDRI or provide an alternate electronic file consistent with EPA's 

reporting form output format. For each reporting period, the quarterly reports must include 

all of the calculated 30-boiler operating day rolling average values derived from the 

CEMS and PM CPMS.

(3) On or after April 16, 2017, submit the compliance reports required under 40 CFR §

63.10031(c) and (d) and the notification of compliance status required under 40 CFR § 

63.10030(e) to EPA’s WebFIRE database by using the CEDRI that is accessed through 

EPA’s CDX (www.epa.gov/cdx). You must use the appropriate electronic reporting form 

in CEDRI or provide an alternate electronic file consistent with EPA's reporting form 

output format.

(4) On or after April 16, 2017, submit the compliance reports required under 40 CFR §

63.10031(c) and (d) and the notification of compliance status required under 40 CFR §

63.10030(e) to EPA's WebFIRE database by using the CEDRI that is accessed through 

EPA's CDX (www.epa.gov/cdx). You must use the appropriate electronic reporting form 

in CEDRI or provide an alternate electronic file consistent with EPA's reporting form 

output format.

(5) All reports required by this subpart not subject to the requirements in 40 CFR §

63.10030(f) introductory text and 40 CFR § 63.10031(f)(1) through (4) must be sent to the 

Administrator at the appropriate address listed in 40 CFR § 63.13. If acceptable to both 

the Administrator and the owner or operator of an EGU, these reports may be submitted 

on electronic media. The Administrator retains the right to require submittal of reports 

subject to 40 CFR § 63.10030(f) introductory text and 40 CFR § 63.10031(f)(1) through 

(4) in paper format.

(6) Prior to April 16, 2017, all reports subject to electronic submittal in 40 CFR § 63.10031(f)

(f) introductory text, (f)(1), (2), and (4) shall be submitted to the EPA at the frequency 

specified in those paragraphs in electronic portable document format (PDF) using the 

ECMPS Client Tool. Each PDF version of a submitted report must include sufficient 

information to assess compliance and to demonstrate that the testing was done properly. 

The following data elements must be entered into the ECMPS Client Tool at the time of 

submission of each PDF file:

(i) The facility name, physical address, mailing address (if different from the physical 

address), and county;

(ii) The ORIS code (or equivalent ID number assigned by EPA's Clean Air Markets 

Division (CAMD)) and the Facility Registry System (FRS) ID;

(iii) The EGU (or EGUs) to which the report applies. Report the EGU IDs as they 

appear in the CAMD Business System;

(iv) If any of the EGUs in 40 CFR § 63.10031(f)(6)(iii) share a common stack, 

indicate which EGUs share the stack. If emissions data are monitored and 

reported at the common stack according to part 75 of this chapter, report the ID 

number of the common stack as it is represented in the electronic monitoring 

plan required under 40 CFR § 75.53 of this chapter;
Attachment C - Page 18 of 24

(v) If any of the EGUs described in 40 CFR § 63.10031(f)(6)(iii) are in an averaging 

plan under §63.10009, indicate which EGUs are in the plan and whether it is a 

30- or 90-day averaging plan;

(vi) The identification of each emission point to which the report applies. An 

“emission point” is a point at which source effluent is released to the atmosphere, 

and is either a dedicated stack that serves one of the EGUs identified in 40 CFR 

§ 63.10031(f)(6)(iii) or a common stack that serves two or more of those EGUs. 

To identify an emission point, associate it with the EGU or stack ID in the CAMD 

Business system or the electronic monitoring plan (e.g., “Unit 2 stack,” “common 

stack CS001,” or “multiple stack MS001”);

(vii) The rule citation (e.g., 40 CFR § 63.10031(f)(1), § 63.10031(f)(2), etc.) for which 

the report is showing compliance;

(viii) The pollutant(s) being addressed in the report;

(ix) The reporting period being covered by the report (if applicable);

(x) The relevant test method that was performed for a performance test (if 

applicable);

(xi) The date the performance test was conducted (if applicable); and

(xii) The responsible official's name, title, and phone number.

j. If you had a malfunction during the reporting period, the compliance report must include the 

number, duration, and a brief description for each type of malfunction which occurred during the 

reporting period and which caused or may have caused any applicable emission limitation to be 

exceeded. [40 CFR § 63.10031(g)]

Records Keeping Requirements

k. You must keep records specified below. If you are required to (or elect to) continuously monitor 

Hg emissions, you must also keep the records required under appendix A and/or appendix B to

Subpart UUUUU. [40 CFR § 63.10032(a)]

(1) A copy of each notification and report that you submitted to comply with Subpart UUUUU, 

including all documentation supporting any Initial Notification or Notification of 

Compliance Status or semiannual compliance report that you submitted, according to the 

requirements in 40 CFR § 63.10(b)(2)(xiv).

(2) Records of performance stack tests, fuel analyses, or other compliance demonstrations 

and performance evaluations, as required in 40 CFR § 63.10(b)(2)(viii).

l. For each CEMS, you must keep records according to the following: [40 CFR § 63.10032(b)]

(1) Records described in 40 CFR § 63.10(b)(2)(vi) through (xi).

(2) Previous (i.e., superseded) versions of the performance evaluation plan as required in 40 

CFR § 63.8(d)(3).
Attachment C - Page 19 of 24

(3) Request for alternatives to relative accuracy test for CEMS as required in 40 CFR § 

63.8(f)(6)(i).

(4) Records of the date and time that each deviation started and stopped, and whether the 

deviation occurred during a period of startup, shutdown, or malfunction or during another 

period.

m. You must keep the records required in Table 7 to Subpart UUUUU including records of all 

monitoring data to show continuous compliance with each emission limit and operating limit that 

applies to you. [40 CFR § 63.10032(c)]

n. For each EGU subject to an emission limit, you must also keep the records specified below: [40 

CFR § 63.10032(d)]

(1) You must keep records of monthly fuel use by each EGU, including the type(s) of fuel 

and amount(s) used.

(2) If you combust non-hazardous secondary materials that have been determined not to be 

solid waste pursuant to 40 CFR 241.3(b)(1), you must keep a record which documents 

how the secondary material meets each of the legitimacy criteria. If you combust a fuel 

that has been processed from a discarded non-hazardous secondary material pursuant 

to 40 CFR 241.3(b)(2), you must keep records as to how the operations that produced 

the fuel satisfies the definition of processing in 40 CFR 241.2. If the fuel received a nonwaste determination pursuant to the petition process submitted under 40 CFR 241.3(c), 

you must keep a record which documents how the fuel satisfies the requirements of the 

petition process.

(3) For an EGU that qualifies as an LEE under 40 CFR § 63.10005(h), you must keep annual 

records that document that your emissions in the previous stack test(s) continue to 

qualify the unit for LEE status for an applicable pollutant, and document that there was no 

change in source operations including fuel composition and operation of air pollution 

control equipment that would cause emissions of the pollutant to increase within the past 

year.

o. If you elect to average emissions consistent with 40 CFR § 63.10009, you must additionally keep 

a copy of the emissions averaging implementation plan required in 40 CFR § 63.10009(g), all 

calculations required under 40 CFR § 63.10009, including daily records of heat input or steam 

generation, as applicable, and monitoring records consistent with 40 CFR § 63.10022. [40 CFR §

63.10032(e)]

p. You must keep the following records for each startup and/or shutdown: [40 CFR § 63.10032(f)]

(1) Records of the occurrence and duration of each startup or shutdown;

(2) Records of the determination of the maximum clean fuel capacity for each EGU;

(3) Records of the determination of the maximum hourly clean fuel heat input and of the 

hourly clean fuel heat input for each EGU; and

(4) Records of the information required in 40 CFR § 63.10020(e).

q. You must keep records of the occurrence and duration of each malfunction of an operation (i.e., 

process equipment) or the air pollution control and monitoring equipment. [40 CFR § 63.10032(g)]
Attachment C - Page 20 of 24

r. You must keep records of actions taken during periods of malfunction to minimize emissions in 

accordance with 40 CFR § 63.10000(b), including corrective actions to restore malfunctioning 

process and air pollution control and monitoring equipment to its normal or usual manner of 

operation. [40 CFR § 63.10032(h)]

s. You must keep records of the type(s) and amount(s) of fuel used during each startup or 

shutdown. [40 CFR § 63.10032(i)]

t. Your records must be in a form suitable and readily available for expeditious review, according to 

40 CFR § 63.10(b)(1). [40 CFR § 63.10033(a)]

u. As specified in 40 CFR § 63.10(b)(1), you must keep each record for 5 years following the date of 

each occurrence, measurement, maintenance, corrective action, report, or record. [40 CFR §

63.10033(b)]

v. You must keep each record on site for at least 2 years after the date of each occurrence, 

measurement, maintenance, corrective action, report, or record, according to 40 CFR § 

63.10(b)(1). You can keep the records off site for the remaining 3 years. [40 CFR § 63.10033(c)]

TABLES TO SUBPART UUUUU OF PART 63

Table 3 to Subpart UUUUU of Part 63—Work Practice Standards

As stated in §40 CFR § 63.9991, you must comply with the following applicable work practice 

standards:

If your EGU is . . . You must meet the following . . .

1. An existing EGU Conduct a tune-up of the EGU burner and combustion controls at least each 36 

calendar months, or each 48 calendar months if neural network combustion 

optimization software is employed, as specified in 40 CFR § 63.10021(e).

3. A coal-fired, liquid 

oil-fired, or solid oilderived fuel-fired EGU 

during startup

If you choose to comply using paragraph (1) of the definition of “startup” in 40 CFR 

§ 63.10042, you must operate all CMS during startup. Startup means either the 

first-ever firing of fuel in a boiler for the purpose of producing electricity, or the 

firing of fuel in a boiler after a shutdown event for any purpose. Startup ends when 

any of the steam from the boiler is used to generate electricity for sale over the 

grid or for any other purpose (including on site use). For startup of a unit, you must 

use clean fuels as defined in 40 CFR § 63.10042 for ignition. Once you convert to 

firing coal, residual oil, or solid oil-derived fuel, you must engage all of the 

applicable control technologies except dry scrubber and SCR. You must start your 

dry scrubber and SCR systems, if present, appropriately to comply with relevant 

standards applicable during normal operation. You must comply with all applicable 

emissions limits at all times except for periods that meet the applicable definitions 

of startup and shutdown in this subpart. You must keep records during startup 

periods. You must provide reports concerning activities and startup periods, as 

specified in 40 CFR § 63.10011(g) and 40 CFR § 63.10021(h) and (i).

For startup of an EGU, you must use one or a combination of the clean fuels 

defined in 40 CFR § 63.10042 to the maximum extent possible throughout the 

startup period. You must have sufficient clean fuel capacity to engage and operate 

your PM control device within one hour of adding coal, residual oil, or solid oilderived fuel to the unit. You must meet the startup period work practice 

requirements as identified in 40 CFR § 63.10020(e).
Attachment C - Page 21 of 24

Once you start firing coal, residual oil, or solid oil-derived fuel, you must vent 

emissions to the main stack(s). You must comply with the applicable emission 

limits within 4 hours of start of electricity generation. You must engage and 

operate your particulate matter control(s) within 1 hour of first firing of coal, 

residual oil, or solid oil-derived fuel.

You must start all other applicable control devices as expeditiously as possible, 

considering safety and manufacturer/supplier recommendations, but, in any case, 

when necessary to comply with other standards made applicable to the EGU by a 

permit limit or a rule other than this Subpart that require operation of the control 

devices.

Relative to the syngas not fired in the combustion turbine of an IGCC EGU during 

startup, you must either: (1) flare the syngas, or (2) route the syngas to duct 

burners, which may need to be installed, and route the flue gas from the duct 

burners to the heat recovery steam generator.

If you choose to use just one set of sorbent traps to demonstrate compliance with 

Hg emission limits, you must comply with all applicable Hg emission limits at all 

times; otherwise, you must comply with all applicable emission limits at all times 

except for startup or shutdown periods conforming to this practice. You must 

collect monitoring data during startup periods, as specified in 40 CFR §

63.10020(a) and (e). You must keep records during startup periods, as provided in 

40 CFR §§ 63.10032 and 63.10021(h). Any fraction of an hour in which startup 

occurs constitutes a full hour of startup. You must provide reports concerning 

activities and startup periods, as specified in 40 CFR §§ 63.10011(g), 63.10021(i), 

and 63.10031.

4. A coal-fired, liquid 

oil-fired, or solid oilderived fuel-fired EGU 

during shutdown

You must operate all CMS during shutdown. You must also collect appropriate 

data, and you must calculate the pollutant emission rate for each hour of 

shutdown.

While firing coal, residual oil, or solid oil-derived fuel during shutdown, you must 

vent emissions to the main stack(s) and operate all applicable control devices and 

continue to operate those control devices after the cessation of coal, residual oil, 

or solid oil-derived fuel being fed into the EGU and for as long as possible 

thereafter considering operational and safety concerns. In any case, you must

operate your controls when necessary to comply with other standards made 

applicable to the EGU by a permit limit or a rule other than this Subpart and that 

require operation of the control devices.

If, in addition to the fuel used prior to initiation of shutdown, another fuel must be 

used to support the shutdown process, that additional fuel must be one or a 

combination of the clean fuels defined in 40 CFR § 63.10042 and must be used to 

the maximum extent possible.

Relative to the syngas not fired in the combustion turbine of an IGCC EGU during 

shutdown, you must either: (1) flare the syngas, or (2) route the syngas to duct 

burners, which may need to be installed, and route the flue gas from the duct 

burners to the heat recovery steam generator.

You must comply with all applicable emission limits at all times except during 

startup periods and shutdown periods at which time you must meet this work 

practice. You must collect monitoring data during shutdown periods, as specified 

in 40 CFR § 63.10020(a). You must keep records during shutdown periods, as 
Attachment C - Page 22 of 24

provided in 40 CFR §§ 63.10032 and 63.10021(h). Any fraction of an hour in 

which shutdown occurs constitutes a full hour of shutdown. You must provide 

reports concerning activities and shutdown periods, as specified in 40 CFR §§

63.10011(g), 63.10021(i), and 63.10031.

Table 5 to Subpart UUUUU of Part 63—Performance Testing Requirements

As stated in 40 CFR § 63.10007, you must comply with the following requirements for performance 

testing for existing, new or reconstructed affected sources:1

To conduct a 

performance test for 

the following 

pollutant . . . Using . . .

You must perform the 

following activities, as 

applicable to your input- or 

output-based emission 

limit . . . Using2. . .

1. Filterable 

Particulate matter 

(PM)

PM CEMS a. Install, certify, operate, and 

maintain the PM CEMS

Performance Specification 11 at 

Appendix B to part 60 of this chapter 

and Procedure 2 at Appendix F to 

Part 60 of this chapter.

b. Install, certify, operate, and 

maintain the diluent gas, flow 

rate, and/or moisture 

monitoring systems

Part 75 of this chapter and 40 CFR §§

63.10010(a), (b), (c), and (d).

c. Convert hourly emissions 

concentrations to 30 boiler 

operating day rolling average 

lb/MMBtu or lb/MWh emissions 

rates

Method 19 F-factor methodology at 

Appendix A-7 to part 60 of this 

chapter, or calculate using mass 

emissions rate and electrical output 

data (see 40 CFR § 63.10007(e)).

5. Sulfur dioxide (SO2) SO2 CEMSa. Install, certify, operate, and 

maintain the CEMS

Part 75 of this chapter and §40 CFR § 

63.10010(a) and (f).

b. Install, operate, and maintain 

the diluent gas, flow rate, 

and/or moisture monitoring 

systems

Part 75 of this chapter and §40 CFR § 

63.10010(a), (b), (c), and (d).

c. Convert hourly emissions 

concentrations to 30 boiler 

operating day rolling average 

lb/MMBtu or lb/MWh emissions 

rates

Method 19 F-factor methodology at 

Appendix A-7 to part 60 of this 

chapter, or calculate using mass 

emissions rate and electrical output

data (see 40 CFR § 63.10007(e)).

3

Incorporated by reference, see 40 CFR § 63.14.

Table 7 to Subpart UUUUU of Part 63—Demonstrating Continuous Compliance 

As stated in 40 CFR § 63.10021, you must show continuous compliance with the emission 

limitations for affected sources according to the following:
Attachment C - Page 23 of 24

If you use one of the following to meet 

applicable emissions limits, operating limits, 

or work practice standards . . . You demonstrate continuous compliance by . . .

1. CEMS to measure filterable PM, SO2, HCl, HF, 

or Hg emissions, or using a sorbent trap 

monitoring system to measure Hg

Calculating the 30- (or 90-) boiler operating day rolling 

arithmetic average emissions rate in units of the 

applicable emissions standard basis at the end of each 

boiler operating day using all of the quality assured 

hourly average CEMS or sorbent trap data for the 

previous 30- (or 90-) boiler operating days, excluding 

data recorded during periods of startup or shutdown.

4. Quarterly performance testing for coal-fired, 

solid oil derived fired, or liquid oil-fired EGUs to 

measure compliance with one or more non-PM 

(or its alternative emission limits) applicable 

emissions limit in Table 1 or 2, or PM (or its 

alternative emission limits) applicable emissions 

limit in Table 2

Calculating the results of the testing in units of the 

applicable emissions standard.

5. Conducting periodic performance tune-ups of 

your EGU(s)

Conducting periodic performance tune-ups of your 

EGU(s), as specified in 40 CFR § 63.10021(e).

6. Work practice standards for coal-fired, liquid 

oil-fired, or solid oil-derived fuel-fired EGUs 

during startup

Operating in accordance with Table 3.

7. Work practice standards for coal-fired, liquid 

oil-fired, or solid oil-derived fuel-fired EGUs 

during shutdown

Operating in accordance with Table 3.

Table 8 to Subpart UUUUU of Part 63—Reporting Requirements

As stated in 40 CFR § 63.10031, you must comply with the following requirements for reports:

You must 

submit a . . . The report must contain . . .

You must submit the 

report . . .

1. 

Compliance 

report

a. Information required in 40 CFR § 63.10031(c)(1) through (4); and

b. If there are no deviations from any emission limitation (emission 

limit and operating limit) that applies to you and there are no 

deviations from the requirements for work practice standards in 

Table 3 to Subpart UUUUU that apply to you, a statement that there 

were no deviations from the emission limitations and work practice 

standards during the reporting period. If there were no periods 

during which the CMSs, including continuous emissions monitoring 

system, and operating parameter monitoring systems, were out-ofcontrol as specified in 40 CFR § 63.8(c)(7), a statement that there 

were no periods during which the CMSs were out-of-control during 

the reporting period; and

Semiannually 

according to the 

requirements in 40 

CFR § 63.10031(b).

c. If you have a deviation from any emission limitation (emission limit 

and operating limit) or work practice standard during the reporting 

period, the report must contain the information in 40 CFR § 

63.10031(d). If there were periods during which the CMSs, including 

continuous emissions monitoring systems and continuous 

parameter monitoring systems, were out-of-control, as specified in 
Attachment C - Page 24 of 24

40 CFR § 63.8(c)(7), the report must contain the information in 40 

CFR § 63.10031(e)