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

P ERMIT #: F ACILITY N AME : L OCATION : C OUNTY : S TATE : NN

- OP

- 1 5

- 06 N AVAJO G ENERATING S TATION P AGE C OCONINO AZ

I SSUE D ATE : E XPIRATION D ATE : AFS P LANT ID: P ERMITTING A UTHORITY :

XX / XX /201 5 XX /

XX /2020 04

- 005

- N04 23 NNEPA

A CTION /S TATUS : P ART 71 O PERATING P ERMIT R ENEWAL I SSUANCE



### 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 other wise 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 N NEPA 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 corres pondence regarding this facility.

Date Dr. Donald Benn

Executive Director Navajo Nation Environmental Pr otection Agency 

# T H E N A

V A JO N A TION RUSSELL BEGA YE PR ES I D E NT

JONATHAN NEZ VICE PRESIDENTPage 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

- NO X 

### B urner (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 Pollutan ts
NMHC Nonmethane H ydrocarbons

NNEPA Navajo Nation Environmental Protection Agency

NNOPR Navajo Nation Operating Permit Regulations

NO X 

### Nitrogen Oxides

NSPS New Source Performance Standards

NSR New Source Review

PM Particulate Matter

PM

- 10 Particulat e 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

SO 2 

### Sulfur Dioxide

US EPA United States Environmental Protection Agency

VCA Voluntary Compliance Agreement

VOC Volatile Organic CompoundsPage 3 of 62



### TABLE OF CONTENTS

Cover Page Abbreviations and Acronyms

I. Source Identification

II. Requirements for Specific Units

A. Federal Implementation Plan R equirements

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. NES HAP 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 System s P. Operational Flexibility

III. Facility

- Wide or Generic Pe rmit 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 ActionsPage 4 of 62



### H. Administrative Permit Amendments

I. Minor Permit Modifications

J. Group Processing of Min or 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 RequirementsPage 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 act s as the facility operator and ha s 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. Bure au of Reclamation (USBR)

2. Los Ange les Department of Water and Power (LADWP)

3. Arizona Publ ic Service Company (APS)

4. Nevada Power Company (NPC)

5. Tu cson Electric Power (TEP)

 Plant Name: Navajo Generating Station

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

 County: Coconino, Arizona

 EPA Region: 9

 Reservation: Navajo Nation

 Tribe: Navajo

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

- 657 7

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 SO 2, NO X, 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 SO 2, NO X, 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 SO 2, NO X, 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

- 8A S,

BC

- 8B S 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 S ystems 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 S ystem

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 H an dling S ystems

SAB

- 1A, SAB

2A, 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 System s PAC Silo A Power active carbon (PAC) sto rage 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

- NO X 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 U 1, U 2, and U 3, 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 SO 2 

### 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 § 49.5513 provides 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 proc ess 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 affirmati ve 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 SO 2 

### emissions for boilers U 1, U 2, and U 3 based on the heat input to each unit as determined by 40 CFR P art 75.

e. Point source means any crusher, any conveyor belt transfer point, any pneumatic material transferring, any baghouse or other control devices

used t o 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 mean s 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 am

bient air quality standard that could be attributed to the emitting source.

h. Shutdown means the time that begin s 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 unti l 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, ther e was an exceedance of the relevant ambient air quality standard that could be attributed to the emitting

source.

i. Oxides of nitrogen (NO X 

### ) means the sum of nitrogen oxide (NO) and nitrogen dioxide (NO 2 

### ) in the flue gas, expressed as nitrogen dioxide.

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

a. Sulfur oxides (SO 2 

### ). The permittee shall not discharge or cause the discharge of sulfur oxides into the atmosphere from boilers U1 , U2 and

U3 in 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 standar d 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 d ust c ontrol p lan 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,

t ruck loading or unloading operation, or railcar unloading station, asPage 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, U 2, or U 3 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 NO X 

### and SO 2 

### and Continuous Opacity Monitoring Systems (COMS) on boilers U1, U 2, and U 3 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, U 2, and U 3, 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 (PM 2

. 5 

### and PM 10 

### ), nitrogen dioxide, sulfur dioxide, and ozone. Operation, calibration and maintenance of the

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

### manu facturer ’ 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. Noth ing 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. § 741 4 , 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 Metho d 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

- 3 990, (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 ofPage 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

prev ent 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

determin ing 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 sha ll 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 th e 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. Subm it 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 leng th 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 certificati ons.

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 plann ing, 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 NO X 

### emissions from boilers U1, U 2, and U 3, from January 1, 2009 to December 31, 2044, may not exceed the 2009

- 2044

NO X 

### Cap (494,899 tons). The per mittee must implement the applicable operating scenario under 40 CFR § 49.5513 (j)(3)(i) to ensure NO X 

### emission reductions sufficient to maintain total cumulative NO X 

### emissions from U1 through U3 below the 2009

- 2044 NO X 

### 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, 2 044 or the date on which the permittee ceases conventional coal

fired electricity generation by all coal

- fired Units at NGS, the permittee must report to U.S. EPA the annual heat input and the annual emissionsPage 15 of 62 

### of sulfur dioxide, carbon dioxide, and NO X 

### fro m the previous full calendar year. In addition, the permittee must also report total cumulative

emissions of NO X 

### from NGS to assure compliance with the 2009

- 2044

NO X 

### Cap and the 2009

- 2029 NO X 

### 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 practi cally enforceable limits for NO X 

### of 0.24 lb/MMBtu, on a 30

- day rolling average basis, f or each u nit equipped with LNB/SOFA, and 0.07 lb/MMBtu, on a rolling average basis of 30 b oiler operating days, for each u nit 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 NO X 

### 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 NO X 

### , diluent, and stack gas

volumetric flow rate from eac h unit. All hourly valid data will be used to determine compliance with the emission limitations for

NO X 

### in Condition I I.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 emiss ion 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 assu rance 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 NO X 

### pounds per hour measurement and the heat input

measurement. The calculation of NO X 

### pounds per h our and heatPage 16 of 62 

### input relative accuracy shall be evaluated each time the CEMS undergo relative accuracy testing.

g. The permittee shall maintain the following record s for each of the coal

fired 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 NO X 

### 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 NO X 

### control technology on boiler U 1, U 2, or U 3. [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 Req uirements [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 : T he 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 sh utdown, the p ermittee 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 l b/MMB tu.

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, Pro cedure 1. The diluent mo nitor (O 2 

### or C O 2 

### ) 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/ MMB tu. 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 C F R 60 Appendix F, Procedure 1. The NOx CEMS

shall meet the quality assurance req uirement 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 U 1 , U2 and U3 on a monthly basis.

b. The permittee shall maintain records of the amount of fuel used in U 1 , 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 an y 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 p ermittee 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 th e 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 natu re 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 ave rage CO and NOx concentration, as measured by the CEMS, exceeds the maximum emission limits set forth in Cond ition

II.B .1

.

g

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

suf ficient data are not obtained to val idate the hour for CO, NOx, or O 2



### .

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 emissi on 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) dur ing 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 determinat ion. 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

em ission limitation in Condition II.D

. 2 of this permit, the permittee shall record the unit’s hourly SO 2 

### emissions using the data from the continuous emission monitoring systems, required in Condition II.D

. 4 of this permit

, and the daily electric energy gene rated by the unit (in megawatt

- hours) as measured by the megawatt

- hour meter for the unit.

b. Compute the average daily SO 2 

### 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 SO 2 

### 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 SO 2 

### emission rate

electric 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 SO 2 

### 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 SO 2 

### 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, an d 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 emissio ns of SO 2 

### , 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 contro l 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 t he 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. A ny periods of emissions fro m 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 hav e 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 syste m design, construction, or operating contractors do not constitute catastrophic failu re [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 ou tages 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

shal l 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 Marc h 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 w ith 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 Administrat or, 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 t he 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 unit

weeks of maintenance in accordance with the plan required in Condition II.D

. 9 of

t his 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 t o 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 Administrato r. 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 Non m etallic Mineral Processing Plants”) and to the emergency fire pump (NGS

- 12 0A) 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 m onitoring 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 th e Administrator for the purposes ofPage 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

d uring 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 base d on information available to the Administrator which may include, but is not limited to, monitoring results, opacity observations, review of operating and maintenance procedure s, and inspection of the source [40 CFR § 60.11(d)]

.

8. For the purpose of su bmitting 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 informa tion, 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 wi th an opacity standard or with a standard which is based on the concentration of a pollutant in the gas es 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, th e 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 a pplies , 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 Non m etallic Mineral Processing Plants”):

1. A ny transfer poin t 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. A ny 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. A ny crusher at which a capture system is not used shall not discharge fug itive 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 em ission limits in Conditions II.F.1, II.F.2, and II.F .3, or the building enclosing the affe cted 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

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

.

6. A ny 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 t he 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 matte r 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 facili ty being tested. Upon written request from the permittee,

NNEPA m ay 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 e missions 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 to ward t he 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 Determ ination 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 w hile 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 visi ble 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 NO X 

### 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 per cent.

3. The permittee shall comply with the following operati ng 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. M eet the requirements of 40 CFR P arts 89, 94 and/or 1068, as applicable.

4. The fire pump must be certified to the em ission 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 § 6 0

. 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) M aintenance checks and readiness testing, provided that the tests are recommended by federal, state or local government, the manufacturer, the vendor, the regional transmission o rganization or equivalent balancing authority and transmission operator, or the insurance company associated with the engine.Page 27 of 62 

### (ii) E mergency demand response for periods in which the Reliability Coordinator under the North American Electric Reliability

Co rporation (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

d ef ined in the NERC Reliability Standard EOP

- 002

- 3.

(iii) F or 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 y ear 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 ano ther 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

par t.

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 ot herwise 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 sh all follow requirements for compl iance 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 expeditiou s 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 re maining 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 C oal

- and Oil

- Fired Electric Utility Steam Generating Units

, 40 CFR Part 63, Subpart UUUUU Requirements

B oiler s 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 inco rporate 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 comp ly 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 sched ule listed in

Condition II.J .1 within 30 days after the c ompletion 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 demo nstrating that it is meeting the requirements under this NESHAP [Extension Approval Letter Dated January 27, 2014]

.Page 29 of 62



### 4

. T he 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, f ilterable PM emissions shall not exceed 0.03

lb/MMBtu or 0.3 lb/MWh.

b. By April 16, 2015, SO 2 

### emissions shall not exceed 0.2 lb/MMBtu or 1.5

lb/MWh.

c. By April 16, 2016, m ercury (Hg) emissions sha ll 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. C onduct 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. SO 2 

### : Operation of the existing SO 2 

### CEMS.

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

.

7

. The permittee shall comply with the applicable complia nce, monitoring, testing, notification, recordkeep ing, 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 forPage 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 DD DDD 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 63.75 7 5( 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 a pplicable, and adjust the burner as necessary to optimize the flame pattern. The adjustment should be consistent with

t he 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 NO X 

### 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).

Measurement s may be taken using a portable CO analyzer; and

f. Maintain on

- site and submit, if requested by the Administrator, an annual report containin g the information specified below:Page 31 of 62 

### ( 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 tak en as a part of the tune

up.

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 re cords :

(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 C F R § 63.10(b)(2)(viii) [40 CFR § 63.7555(a)(2)]

.

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

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

( d ) R ecor ds of the calendar date, time, occurrence

, and duration of each startup and shutdown [40 CFR § 63.7555(i)]

.

( e ) R ecords 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 fol lowing: [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 endin g dates of the reporting period;Page 32 of 62 

### (d ) The total operating t ime during the reporting period;

(e ) T he 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 Interna l Combustion Engines

, 40 CFR Part 60, Subpart IIII

, specified in Condition II.H

, f ulfills the requirements of this NESHAP [40 CFR § 63.6590(c)].

2

. T he permittee shall comply with the following work practice requirements for engine s 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 5 00 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 NPG

746 shall be limited to the following [ 40 CFR § 63.6640(f)] :Page 33 of 62 

### 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) M aintenance 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) E mergency 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 Emergencie s (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

d efined in the NERC Reliability Standard EOP

- 002

- 3.

(iii) F or 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 y ear 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 emergen cy generators EG2, EG3, and NPG

- 746 [ 40 CFR § 63.6655]:

a. R ecords of the maintenance conducted on the stationar y RICE [ 40 CFR § 63.6655(e)].

b. R ecords 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 sp ent for non

emergency 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 a nd 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, t he permittee shall comply with the fol lowing 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 onPage 35 of 62 

### a continuous bas is 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 ea rliest 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 ti me 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 ofPage 36 of 62 

### 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

a ssurance 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 pe riods 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 par t 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 caus ed 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

respo nse 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 syste m, and thePage 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 res ults 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 determi nation 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 per mit 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 appli cable) 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 ze ro 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 o f 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 take n, any written QIP required pursuant to 40 CFR § 64.8 and any activities undertaken to implement a QIP , and other supporting information requiredPage 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 tr affic 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 deliv ery, 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 notPage 39 of 62 

### modifications under Title I of the Clean Air Act . This class of changes

does not include:

(i) Changes that would violate a pplicable 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) chang e, 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, a nd 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 emission s units located at the facility [See 40 CFR § 71.6(a)(1)]

.

III.A. Testing Req uirements [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 T est 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 An alysis 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 test s shall be performed at maxim um 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

ad justments 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 w ith 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 t est 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 an d 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, o r 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 o f 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; adjustm ents 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

measurement s, m aintenance, 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

30 th 

### 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 officia l consistent with Condition

III.C.4 of this perm it.

a. A monitoring report under this section must include the following:

(i) The company name and address.

(ii) The beginning and endin g dates of the reporting period.

(iii) The emissions u nit or activity being monitored.

(iv) The emissions l imitation 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 durin g the reporting period, and the total downtime of the continuous monitoring system during the reporting period.Page 43 of 62 

### (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 result s, 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 d escribed 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 establis hed 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 wh en 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 col lected 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 und erlying 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

time frame 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 h our in excess of permit requirements, the report must be made by telephon ic

, 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 telephon ic

, 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 c onditions 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

t his 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 Stratosphe ric 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 C lass I substance being introduced into

interstate commerce must be ar warning statement s 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 arePage 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 in terstate 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 pla cement 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 emission s reduction pursuant to 40 CFR Part 82, Subpart F, except as provided for motor vehicle air conditioners (MVACs) in Subpart B [ 40 CFR § 82.15 0(b)] :

a. Persons opening appliances for maintenance, service, repair, or disposal must comply with the requir ed p ractices 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 pu rsuant to 40 CFR § 82.158.

c. Persons performing maintenance, se rvice, 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 appl iances 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 substitu te 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 refrigera ted 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

Pro gram (SNAP) promulgated pursuant to 40 CFR Part 82, Subpart G.

II I

. 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



### I V

. Title V Administrative Requirements

I V .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. F ee payment s shall be remitted in the form of a money order or certified

check made payable to the Navajo Nation E nvironmental 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 fe e 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 regul ated 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 PM 10 

### , 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 pollutantPage 48 of 62 

### in exces s 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 d efined 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

ha zardous 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 permitte e 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 t imely manner shall subject the permittee

to assessment of penalties and interest in accordance with NNOPR § 603(C)

.

7. When notified by NN EP A of underpayment of fees, the p ermittee shall remit full payment within 30 days of receipt of notification [ 40 CFR § 71. 9 ( j )( 2 ) ]

.

8. A p ermittee who thinks an NN EPA a ssessed fee is in error and wishes to challenge such fee, shall provide a written explanation of the alleged error to

NN EPA along with full payment of the NN EPA assessed fee

. W ithin 90 days of receipt of the correspondence, NNEPA shall review the data to determine whetherPage 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 ) ]

.

I V .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 inspecti on, 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. I t 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 w ork 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 perm it

- 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 m ethods 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 meansPage 50 of 62 

### designated above. The certification shall identify each d eviation 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.

I V .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. U pon 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 accompani ed by a claim of confidentiality according to the provisions of 40 CFR Part 2, S ubpart 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.

I V .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 belie f 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 calc ulation 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 86504Page 51 of 62 

### and

Director, Air Division (Attn: AIR

- 1) EPA Region IX

75 Hawthorne Street San Francisco, CA 94105

I V .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.

I V .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

no ncompliance

, 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 th e 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 operati onal control of a source where the

NN EPA 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 pe rmittee has

been submitted to the NN EPA ;

5. Incorporates into the P art 71 permit the requirements from preconstruction review permits authorized under an EPA

- approved program, provided that such a program meets procedural requirements substantially equiva lent to the requirements of 40 CFR § § 71.7

, 71.8 and 71.10 that would be applicable to thePage 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 NN EPA 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 th is permit.

c. Do not require or change a case

- by

- case determination of an emission s 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 federall y enforceable emissions cap assumed to avoid

classification as a modif

ication under any provision of Clean Air

Act T itle I; and

(ii) An alternative emissions limit approved pursuant to regulations promulgated under S ection 112(i)(5) of the Clean Air Act.

e. Are not modifications under any provision of T itle 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 modific ation 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 suc h 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 require ments 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 out line 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 take s 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 wi th 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 exten d 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 NN EPA may be used only for those permit

modifications:

a. That meet the criteria for minor permit modification pr ocedures under

Condition IV.I.1 of this permit; and

b. T hat collectively are below the threshold level of 10 percent of the

emissions allow ed 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 requirement s 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 wheth er 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 onl y 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 change s proposed in its minor permit modification application immediately after it files such application. After the source makes the change s 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.

Ho wever, 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 ex tend to group processin g 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 P art 71 that would render existing permit compliance terms and

conditions irrelevant.

3. The permittee must meet all requirements of P art 71 for applications for significant permit modifications. For the application to be determined complete,

the permi ttee 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)]

.

I V

. L . Reopening for Cause [40 CFR § 71.7(f)]

NN EPA 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 P art 71 source with a remaining permit term of 3 or more ye ars.

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 p ermit.

3. NN EPA 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. NN EPA or US EPA determines that the permit must be revised or revoked to assure compliance with the applicable requirements.

I V .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.

I V .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. E nter 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 th is permit;

2. H ave access to and copy, at reasonable times, any records that must be kept under

the conditions of th is permit;

3. I nspect at reasonable times any facilities, equipment (including monitoring and air pollution control equipment), practices, or operations regulated or required under the permit; and

4. A s authorized by the Clean Air Act, sample or monitor at reasonable times

substance s 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 operati ng 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 perm ittee 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 NN EPA within 2 working days of the time when emission s 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 emission s limitation

under th is 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.

I V .P

. Transfer of Ownership or Operation [40 CFR § 7 1.7(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

.

I V .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. E ach change is not addressed or prohibited by this permit ;

2. E ach change must comply with all applicable requirements and may not violate any existing permit term or condition;

3. C hanges under this provision may not include changes or activities subject to any requirement under 40 CFR Parts 72 through 78 or that are modif ications under any provision of Title I of the Clean Air Act;

4. T he 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). T he 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. T he permit shield does not apply to changes made under this provis ion; and

6. T he 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.

I V .R

. Permit Expiration and Renewal [40 CFR §§ 7 1.5(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; orPage 58 of 62 

### b

. the source is issued a Part 70 permit by NNEPA, provided that EPA has granted the Navajo Nation t reatment 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 permi ttee ’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 p ermit 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 p ermittee ’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 t o 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 requirem ents 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 rev iewing 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, bu t 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 o f the Clean Air Act and are subject to full Federal enforcement

authorities available under the Clean Air A ct.Page 60 of 62 

# Attachment A

Dust Control PlanPage 61 of 62 

# Attachment B

Phase II Acid Rain Permit RenewalPage 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 RequirementsNavajo 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

- 1 5

- 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

p articipant in this permit since it act s as the facility operator, and ha s accepted the responsibility to obtain environmental permits for Navajo Gen erating Station, including an Acid Rain permit and Part 71 Permit. In addition to SRP (21.7%) , the other 5 co

owners 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%) 

# T H E N A

V A JO N A TION RUSSELL BEGA YE PR ES I D E NT

JONATHAN NEZ VICE PRESIDENTPage 2 of 29 

### 5

. Tucson Electric Power (TEP) (7.5%)



### b. Contact I nformation

Facility Contact: Paul Ostapuk Phone: ( 928) 645

- 6577

O&M Manager Facsimile: (928) 645

- 7298

Responsible Official: Rober t K. Talbot Phone: (928) 645

- 6217

Plant Manager Facsimile: (928) 645

- 7298



### c. Description_of_ O perations,_ P roducts

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 SO 2



### scr ubbers 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 byproduct s. 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 coa l

, which has an average sulfur content between 0.5% and 0.75% by weight

, from a nearby coal mine

. Coal

- fired b oilers 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 regulation s

.

Particulate emissions f

ro m boilers U1 through U3 are controlled by Electros tatic Precipitators (ESP). Flue Gas Desulfurization (FGD) systems for SO 2 

### control were installed in 1997, 1998, and 1999 on boilers U3, U 2, and U1, respectively. The

associated limestone handling sys tem was constructed in 1997

. In 2008, the source received a PSD permit to install Low

- NO X 

### burners (LNBs) and Separated Over

- fire Air (SOFA) systems on the three existing boilers. The LNB/SOFA sy stems 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 Feb ruary 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 coalPage 3 of 29 

### handling operation at the facility. The refined coal system will be owned and operated by a thi rd

- 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 P art 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 increase s of emissions from these units

and is considered a minor permit modification

.

(2) Revise the ins ignificant 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 S tationary Compression Igniti on Internal Combustion Engines ( 40 CFR Part 60, Subpar t IIII) and the applicable requirements of this NSPS will be included in this P art 71 permit. These changes ar e 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 equipmentPage 4 of 29 

### decreases the particulate emissions from these units and is considered a minor permi t modification

.

(4) Add o perating 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 In stitutional Boilers and Process Heaters ), the permittee requested to include an operating limit of 10% of the annual capacity

in to this P art 71 renewal permit for the auxiliary boilers. This P art 71 permit will also include additional recordkeeping require ments for these auxiliary boilers. These p roposed 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 state d 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, Subp art UUUUU is most stringent applicable PM emission limit for boilers U1, U2, and U3, operating PM CEMS according to the NESHAP requiremen ts e xempts 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 re ceived on March 31 , 2015, t he 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 requi rements to the Part 71 permit is considered a significant permit

modification.

The procedure for review ing 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 signi ficant 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 SO 2, NO X, 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 S 2 One (1) pulverized coal

- fired boiler,

using No. 2 fuel oil for ignition fuel. Stack S1 is equipped with SO 2, NO X, 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 SO 2, NO X, 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

- 8A S

, BC

- 8B S 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 S ystems 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

- 9Page 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 S ystem

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 H an dling S ystems

SAB

- 1A, SAB

2A, 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 S ystem s PAC Silo A P ower active carbon (PAC) sto rage 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

- NO X 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 uni t 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 emission s from a n 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) Nin e (9) d iesel

- 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 f acility

- wide welding activities, identified as WL.

(c) Equipment used during a brasive blasting operations.

(d) Fuel and oil stora ge 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 550Page 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 500Page 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 p owder coating operations.

(h) Lab equipment used exclusively for chemical and physical analyses.

(i) Equipment used during m aintenance painting and surface coating.

(j) Equipment used during p arts cleaning.

(k) Equipment used during m aintenance 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 12Page 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 orPage 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 PM 10 PM2.5 SO 2 NOx VOC CO HAPs

Boiler U 1 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 U 3 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

- - - - -

U npaved 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 3,51 3 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 PM 10 

### , PM 2.5 

### , SO 2 

### , VOC, CO and NO
x 

### are equal to or greater than 100 tons per year. In addition, the potential to emit of HAPs fromPage 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 H APs. 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. T his information

ref lects the 2012 emission inventory data submitted by the permittee to NNEPA and

the g reen h ouse g as (GHG) information reported to U.S. EPA under the GHG reporting program (40 CFR Part 98)

.

Pollutant Actual Emissions (tons/year)

PM 10 

### 432

SO 2 

### 4,404

VOC 200

NO
x 

### 16,276 Hydrogen Chloride 6.0 Hydrogen Fluoride 9.0

Green h ouse 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 2 7 ,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

dist ribution, 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 establish ed.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 modifi cations in 1997 (installation of the FGD systems) and 2008 (installation o f 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 modification s in 1997 (installation of the FGD systems) did not result in an emission s increase above the PSD significan ce thresholds in 40 CFR § 52.21. Therefore, the modification that commence d in

1997 did not trigger PSD.

A PSD permit was issued to this source on July 3, 2008 for the inst allation 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 emi ssion 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) NO
x 

### 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

perm its.

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 s ource

- s pecific 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 Availa ble Retrofit Technology (BART) r equirements.

Pursuant to 40 CFR § 49.5513(d), the permittee shall comply with the following

emission limits on a plant

- wide basis:

(1) The SO 2 

### emissions shall not exceed 1.0 lb/MMBtu averaged over any three

hour 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, opa city shall not exceed 20% averaged over a 6 minute period

, excluding condensed water droplets, or 40% averaged over 6 minutes during ab sorber upset transition periods, pursuant to 40 CFR § 49.5513 (d)(4).

For dust emissions associated with coal transfer an d storage and other dust

- generating

activities , o pacity 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 receive d on February 2, 20 15. The revis ed 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 Au gust 8, 2014 to include BART requirements (effective October 7, 2014) . Pursuant to 40 CFR § 49.5513(j)(3)

, t otal cumulative NO X 

### emissions from Units 1, 2, and 3, from January 1 , 2009 to December 31, 2044 shall

not exceed the 2009

- 2044 NO X 

### Cap (494,899 tons ). Compliance with this NOx emission limit must be demonstrated by the operation of the existing NO X 

### CEMS. The applicable operating, maintenance, recordkeeping, and reporting requirements for the NOx CEMS specified in the FIP have been incorporated into th is 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 NO X 

### 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 n o later than December 31, 2020 to incorporate the specific requirements, including compliance monitoring, recordkeeping, and reporting requirements, associated with the selected operating

scen ario.

( 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 7 8 ), 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 SO 2 

### and N O X 

### 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 SO 2 

### allowanc e allocations for the boilers at this source are

listed in the table below:

Emission

Unit SO 2 

### 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 SO 2 

### allowance allocations apply to the entire facility, instead of each individual emission unit at this facility.

(3) A cid rain emissions limitations for nitrogen oxides in 40 CFR Part 76 for coal

fired 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) include s the following specific requirements for the three (3) co al

- fired boilers at Navajo Generating Station : (1)

Pursuant to 40 CFR § 52.145(d)(2), the SO 2 

### 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 f ossil

- fuel fired steam electri c 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 repr esenting 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 reasonabl e 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 sour ce

- specifi cPage 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

, 200 5 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 vacate d 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 (EGU s ) 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 applicatio n 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.

T he 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, f ilterable PM emissions shall not exceed 0.03 lb/MMBtu or

0.3 lb/MWh.

(2) By April 16, 2015, SO 2 

### 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 SO 2 

### emission limit in this NE SHAP 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 in stalled 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 201 5.

The associated compliance, monitoring, testing, notification, recordkeeping, and reporting requirements are included in the permit as Attachment C. Please note that t he 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

reconstruct ion to the boilers has occured since the construction of these boilers.

Therefore , the New Source Performance Standard s (NSPS) for Fossil

- Fuel

- Fired

Steam Generators (40 CFR Part 60, Subpart D) , which apply to generators that

commenced construction or modi fication 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

P art 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), pur s uant 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 thePage 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 . T here 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 enforceab le 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 quali f y for “limited

- use” unit status. The permit tee has requested the inclusion of this opertati ng 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

const ruction 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 Standard s 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 thi s source commenced construction after Aug ust 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 l imestone h andling s ystem

.

Pursuant to 40 CFR § 60.672, the permittee s hall comply with the following emission

limitations:

(1) E missions 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 t he 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 b aghouse 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 reportin g 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

. T herefore, this unit is subject to the requirements of the New Source Performance Standards f or 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 th ese NSPS because they were either installed before

A pril 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

. T he emissions from this unit shall comply with the following

emission limits, pursuant to 40 CFR § 60.4205(c) and Table 4 of th ese NSPS:

(1) NMHC + NO X 

### 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 § 60.4 207(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, 2 010, may be used until depleted.

The permittee shall comply with the operati ng 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, p ursuant 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, SubpartPage 21 of 29 

### ZZZZ). S tation ary 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,

S ubpart 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) I nspect air cleaner every 1,000 hou rs or annually ;

(3) Inspect hoses and bel ts every 500 hours or annually; and

(4) M inimize 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 wh ich time the non

- star tup emission limitations apply.

The initia l 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 c omplying 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,

S ubpart 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 C ommenced A fter June 11, 1973, and

Prior t o May 19, 1978 (40 CFR Part 60 , Subpart K) are not applicable

.

(n) T ank NGS

- 06 4

- 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 C ommenced A fter May 19, 1978 and Prior to July 23, 1984 (40 CFR

Part 60 , Subpart Ka) are not applicable

.

( o ) The diesel storage tank NGS

- 075 B 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 e xempt from the requirements of the New Source Performance

Standards for Volatile Organic Liquid Storage Vessels for Which Construction, Reconstruction, or Modification Commenced Afte r 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 SO 2

, 

### NO X 

### , 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 SO 2

, 

### NO X 

### , and CO emission limits. These requirements have been incorporated into this part 71 renew al permit. Therefore, the

S O 2

, 

### 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 emissio n limits specified in NESHAP, Subpart

UUUUU. Since the PM emission limit in this NESHAP is more stringent than the PM

em ission limits in FIP, compliance with the PM emission limit for NESHA P , Subpart UUUUU using the new PM CEMS is sufficient to demonstrate compliance w ith PM

emission limit in FIP. Therefore, the PM emissions from boilers U1 through U3 a re 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 t o 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

scrubbe r 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 145 0 F 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 scru bber 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 145 0 F 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/PM 10 

### 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. T he pre

- control PTE of baghous e DC

- 9, DC

- 10, and DC

- 11 is each less than the ma jor source threshold of 100 tons/yr . T herefore

, 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 Asbesto s NESH AP (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 perm it

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

- 7 8 ) 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, Sub part DDDDD) Current

NESHAP for Stationary Reciprocating Internal Combustion Engines (40 CFR Part 63, Subpart ZZZZ) Current

Asbestos NESHAP (40 CFR Part 61, Subpart M) CurrentPage 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 r eopening 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, i f 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 w eekly visual emission survey of the exhaust stacks of baghouses DC

- 9, DC

- 10, and DC

- 11 w hile 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 w hile the equipment is operating in

accordance with 40 CFR § 60.675.

( 3 ) The permittee shall r ecord and maintain the following records for each visible emission observation or Method 9 opacity test:

(i) the date and time of the observati on 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 result s 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 emissi on control system ( including a n ew powdered activated carbon (P A C ) injection system and a new calcium bromide application system ) :

(1) Vehicle miles travel (VMT) for truck traffic associated with the delivery ofPage 27 of 29 

### P A C 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 re cords 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 F ederally

- 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 perm it 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 i ssuance 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 tes ting 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 thePage 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 Nava jo Nation EPA a nd US 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 ren ewed. 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 revi ew 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

- 424 8 . 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, y ou 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 r ecord that can be obtained by request. A statement of reason s for any c hanges 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 argument s 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 ar e 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 followi ng 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 pe rmit. 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 inf ormed 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)

PM a PM10 b PM2.5 b SO 2 c NO X d VOC e CO d

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 SO 2 emission factor is based on the emission limit in 40 CFR 52.145(d).

d The NO X 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, SO 2 , 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

7,410Page 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)

PM a PM10 b PM2.5 b SO 2 c NO X d VOC e CO d

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 SO 2 emission factor is based on the emission limit in 40 CFR 52.145(d).

d The NO X 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, SO 2 , 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

7,410Page 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)

PM a PM10 b PM2.5 b SO 2 c NO X d VOC e CO d

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 SO 2 emission factor is based on the emission limit in 40 CFR 52.145(d).

d The NO X 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, SO 2 , 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

7,410Page 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 lbsPage 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 SO 2 NO

x 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/hrPage 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/hrPage 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/yrPage 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/yrPage 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/yrPage 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/yrPage 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 TypePage 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 SO 2 NO

x 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)

2,861Page 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 SO 2 NO

x 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

N avajo 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

## Ta ble of Contents

1. INTRODUCTION AND PURPOSE

2. FACILITY DETAILS

3. GEOGRAPHY AND CLIMATE

4. DUST SUPPRESSION METHODS Federal Implementation Plan Re quirements

- 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 HA NDLING 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 Form s

9.3 Visible Emissions Form1.0 INTRODUCTION AN D PURPOSE

Salt River Project’s (SRP’s) Navajo Generating Station (NGS) facility is committed to responsible and sustainable stewardship of the environment ; and compl iance 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 promulgati on 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 activ ities . 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 parti cipant 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%), S alt 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.

Bit uminous coal is mined by Peabody Energy at the Black Mesa Mine Complex and delivered by

electric rail to NGS. C oal is then transferred via enclosed conveyor system s for burning in the

boilers or stacked out to a storage pile for later use

.

The m anageme nt 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. Co al combustion residues include flyash, bottom ash, and scrubbe r byproducts. B ottom 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 GEO GRAPHY 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 o f 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 em issions from paved and unpaved roads, storage piles, and the material handling related to coal

, fly ash , and limestone

.

4.1 Road ways

D ust emissions from roadways are mitigat ed using control measures outlined below. Main

trafficked areas are sprayed wit h 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 t he 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. Wa ter 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 event s

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 cat egories

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) sur face

treatments.

Material Disturbance and Wind Erosion Control Measures : Source control 1. Minimize exposed surface area

2. Minimize surface disturbance s and material handling Source improvement 1. Reduce d rop height when handling material

2. Maintain m oisture an d crust , as applicable

3. Shelter from w ind , as applicable

Surface treatment 1. Water Spray ing

, as applicable

2. Chemical stabilization

Monitor: Verify control measures weekly.

4. 3 Coal Handling

SRP’s responsibilities extend to all aspects of coal handling an d storage; t his includes implementing dust control measures for the following :

Coal Handling Non

- Point Source s : One or more of the foll owing control measures will be implemented by NGS to minimize dust emissions from the potential sources listed below:

T ABLE 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. Wa tering 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 m oisture (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

- enclosureBelt 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

- enclosu re 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 Source s : The potential sources listed in Tabl e 4.0 utilize particulate control

devices to control emissions

.

TABLE 4

. 0 Emission Control Device s : Unit ID / Stack ID: Control Device Make / Size Stack D etails

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 E xit opening is

outside building facing west

. Opening: 3 fee t 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 thr u 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 feetSilos 2A thru 2G DE

- 3 & DE

- 4 (Cascade Enclosure

- 135 feet elevation) SIEMENS and

PR

- 2, S R

- 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

SR P’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 activit i es in Ta ble 5.1 are managed by SRP. O ne or more of the foll owing control measures

are implemented to minimize dust emissions from the se potential sources

.

TABLE 5

. 0 Control Measure Guidelines : Source: Material Handling and Roadway Control M easure(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 e vent 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) Spillag e (conveyance from
post

- furnace to enclosed silos) 1. Enclosure

2. Rapid cleanup after spill event sMonitor: Verify control measures weekly.

Flyash Point Source s : 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 Device s : Unit ID / Stack ID: Control Device Make / Size Stack D etails

Silo 1 ( storage activity) DC

- S1/2 ( baghouse on top of

Silo 1 ) Sc ientific 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 facin g

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 t op 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 ar e 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 requiremen ts.

Limestone Handling Non

- point Sources:

Table 7 .0 Control Measur e Guidelines : Source: Control Measure(s) Material Handling: Unloading Bay A and B (truck un loading operations) N ot Applicable

- Truck dumping of non

- metallic miner als 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 P oint 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 Eq uipment

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

- FMCF

07

- 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 o bservations 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, f eed 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 P oint Sources: The potential source s listed in Table 9.0 utilize particulate control devices to control emissions.

Table 9 .0

Control Devices: Unit

ID / Stack I D: 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 E xhaust opening

facing south on top of baghouse. Opening: 6” I.D.

LB

- 1 & L B

- 2 (water treatment

lime storage activity) DC

- BH7 (baghouse on top of

Bin 1) Scientific Dust

Collectors Exhaust opening

facing south on top of bag house. 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 c ontrol devices will be opera ted and

maintained w ith opacity emission limit s 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 non

point sources the i nspectors shall document active control measures that are being used to

minimize dust emissions . In the case of point sources

, the observe rs 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 F orms

6 .0 RECORD KEEPING AND REPORTING

SRP will maintain records of weekly inspection records

, Method 9 certifi cation training, and

Method 9 observations.

SRP will make reports as necessary in accordance with the Federa l 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.

Th e notification s 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 Prote ction 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 emissio ns; (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 S weeper 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 T ruck

Owner: SRP Make: International, Supersucker Model 5227, 15 cubic yard capacity

8 .0 TRAINING

At least t wo (2) on

- site person ne l will obtain EPA Method 9 certification s and r eceiving training regarding weekly inspections and provisions of this plan

. A copy of the NGS FIP D ust C ontrol

Plan will be made available to plant personnel and the third party contractor responsible for handling coal combustion residues and limestone del iveries.

9 .0 ATTACHMENTS

9 .1 Facility Map

9

. 2 Weekly Inspection Form s

9

. 3 Visible Emissions Form

## Facility Map

## Weekly Inspection Forms

### WEEKLY INSPECTION FORM S

NGS FIP WEEKLY OBSERVATIONS

– 20% OPACITY LIMIT

Certified Observer (Circle) Walte r 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)

Rai lroad 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. Shelte r 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

- enclosur e 2. Water spray ing

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

- enclosureSRP/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 re claim 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)

PARTICULA TE CONTROL DEVICES

Source (Unit ID) Control Device Is Control

Device Operating? (C heck one ) Is there VE?

(C heck one ) Was EPA

Method 09

conducted? (C heck one )

YES NO YES NO YES * NO **

YSB

- 1

DC

- 8 BC

- 8A & BC

- 8B

BC

- 8A & BC

- 8B screening op eration

PSB

- 1 D E

- 5 BC

- 9A & BC

- 9B

BC

- 10A & BC

- 10B

CC

- 6A/6B &

Silos 1A thru 1 C (coal silos) D E

- 1

CC

- 4A/4B, CC

5A/5B &

Silos 1 D thru 1G (coal silos) D E

- 2

Cascade Enclosure PR

- 1 SR

- 1 EX

- 1

* Note: Comple te 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 St orage

- Continued )

PARTICULATE CONTROL DEVICES

Source (Unit ID) Control Device Is Control

Device Operating? (C heck one ) Is there VE?

(C heck one ) Was EPA

Method 09

conducted? (C heck one )

YES NO YES NO YES * NO **

CC

- 3A/3B, CC

11A/11B &

Silos 2A thru 1 C (coal silos) D E

- 3

CC

- 1A/1B, CC

2A/2B &

Silos 2 D thru 1G (coal silos) D E

- 4

Cascade Enclosure PR

- 2 SR

- 2 EX

- 2

CC

- 7A/7B, CC

8A/8B &

Silos 3A thru 1 D (coal silos) D E

- 6

CC

- 9A/9B &

Silos 3 E thru 1G (coal silos) D E

- 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?

(C heck one ) Is there VE?

(C heck one ) Was EPA

Method 09

conducted? (C heck one )

Y ES 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 w as 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?

(C heck one ) Is there VE?

(C heck one ) W as EPA

Method 09

conducted? (C heck 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 Observat ion 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 ROA DWAY 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. Spe ed reduction

4. Limit traffic

5. Gravel surfaceSRP/NGS

Non

- Point Sources ( Fly Ash Handling and Storage)

MATERIAL HANDLING AND ROADWAY CONTROL MEASURES

Source Control Measure (s) Implemented (Circle) Comments: Spillag e (conveyance from
post

- furnace to

en closed silos) 1. Enclosure

2. Rapid cleanup after spill event s

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. Sweepin g 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 A ctivity 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? (C heck one ) Is there VE?

(C hec k one ) Was EPA

Method 09

conducted? (C heck one )

YES NO YES NO YES * NO **

SAB

- 1A, SAB

- 2A,

SAB

- 1B, SAB

- 2B (water treatment

soda ash storage activity) D E

- BH6

* Note: Complete one Method 9 VE Observation Form for each control device if visible emis sions 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 Contr ol

Device Operating? (C heck one ) Is there VE?

(C heck one ) Was EPA

Method 09

conducted? (C heck 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?

(C heck one ) Is there VE?

(C heck one ) Was EPA

Method 09

conducted? (C heck 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

- SILO

A&B DC

- 11 (7% Opacity Limit)

Point and Non

- Point Sources (Limestone Handling and Storage)

MATER IAL HANDLING AND STORAGE MEASURES

Source CIRCLE Control Measures Implemented (LIMIT) Comments:

O

- LSP

- FDR

A&B, O

- LSP

CNV

- A&B 1. Enclosure s

- Pt. Src. Opacity Limit s: F rom baghouses, stacks and bldg. vents/openings 7%

2. Non

- Enclosed

- F ugitive Src. Opacity L imits: 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 FormSRP/NGS VISIBLE EMISSION OBSERVATION FORM

Observat ion 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. Vent s

Coal Material Handling
FIP Dust Co ntrol 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 Ha ndling
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 rel ation 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 emissi ons 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 co mposed 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 Ostap uk 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 I V of the Clean Air Act and 40 C.F.R.

Part s 72 thro ugh 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

### A cid 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. T he Permittee shall not discharge or cause the discharge of NO
x 

### from each pulveriz ed 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 incorporat e s 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 (A IR

- 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 expiratio n date

.

### A cid Rain Permit No. NN 13

- 01



## Appendix A

Acid Rain Permit ApplicationAttachment C

- Page 1 of 24



### C ompliance , Monitoring, Testing, Notification, Recordkeeping, and Reporting R equirements under NESHAP, S ubpart UUUUU for Coal

- and
Oil

- Fired Electric Utility Steam Generating Units

[Based on the rule version d ated as March 24, 2015 ]



### Note: The requirements pertaining to Hg emissions are not applicable until April 16, 2016.



### I

. G ENERAL 

### C OMPLIANCE 

### R EQUIREMENTS

a

. At all times you must operate and maintain any affected source, including associated air pollution control equipment and monitoring eq uipment, 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 contin uous 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 d ry 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 wit h part 75 of this chapter to demonstrate compliance with the applicable SO 2 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 on e 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 coal

fired, 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 site

specific monitoring plan and submit this site

- specific monitoring plan, if requested, at least 60Attachment 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 Admin istrator 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 appen dix 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 tha t 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

downst ream 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 pe riodic 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 maintena nce 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 co nsistent 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. T ESTING AND 

### I NITIAL 

### C OMPLIANCE 

### R EQUIREMENTS

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 th an 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 SO 2 or PM CEMS, the initial performance test consists of 30

- (or, if emissions averagin g 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 SO 2 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,
CO 2 , O 2 , 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 emis sion limit, you must also collect hourly electrical load data
duri ng 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 mon itoring 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) requiremen ts 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. Y ou may demonstrate initial compliance with the applicable SO 2 emissions limit in Table 2 to this subpart through use of an SO 2 CEMS installed and operated in accordance with part 75 of this chapter or appendix B to this subpart, as appli cable. 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 SO 2 or PM emissions
limit in Table 2 to this subpart. Use Equation 19

- 19 of Method 19 in appendix A

- 7 to p art 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

ope rating days of quality

- assured sorbent trap monitoring syst em 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 af fected EGUs are subject to the work practice stan dards 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 you r 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 s pecified 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

. Y ou must follow the s tartup 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 )]

S ubsequen t 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 requir ed in 40 CFR §

63.10031. [40 CFR § 63.10006(j)]

M ethods 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, SO 2 , 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 § 63.1001 1(g) and Table 3 to 40 CFR 63, Subpart UUUUU ), except as otherwise prov ided 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) a nd 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 th e 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 applicabl e 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

com ponents 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/M MBtu 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

- facto rs 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 SO 2 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 A

3 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 SO 2 , 9.43 × 10

− 8 lb/scf

- ppm for HCl (if an HCl CEMS is u sed), 5.18 × 10

− 8 lb/scf

- ppm for HF (if an HF CEMS is used), or 6.24 × 10

− 8 lb

- scm/mg

- scf for HAP metals and for HCl and HF (when performance stack testing is used), and defining C h as the average SO 2 , HCl, or HF concentration in ppm, or the average HAP me tals 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 t he performance test (megawatts). If the applicable emission limit is in lb/MWh rather than lb/GWh, omit the 10 3 term 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, SO 2 , 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 th e 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 y ou 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 CO 2 concentration is below the cap val ue or the measured O 2 concentration is above the cap v alue:

(i) For an IGCC EGU, you ma y use 1% for CO 2 or 19% for O 2

.

(ii) For all other EGUs, you ma y use 5% for CO 2 or 14% for O 2

.

(2) Default electrical load. If you use CEMS to continuously monitor Hg, HCl, HF, SO 2 , 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 emiss ion 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 operatin g 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 a veraging method as described in 40 CFR § 63.10009 to demonstrate compliance with the filterable PM, SO 2 , 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 o f 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 SO 2 or PM emissions for initial compliance, the first 30 boiler operating day average emission rate ob tained 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 demonstrat ed if the results of the performance test meet the applicable SO 2 orAttachment 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 em issions, 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 start up periods or shutdown periods.

(2) You must operate all CMS, collect data, calculate pollutant emission rates, and record data during startup periods or shutdown per iods.

(3) You must report the inform ation 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

yo u 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 us e an alternative non

- opacity emissions standard, as described be low.

(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 fin al 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 manufa cturer

- identified safely issue.

(iv) The request shall provide inf ormation to document that the PM control device is adequately designed and sized to meet the PM emissi on limit applicable to the
EGU.

(v) In addition, the request sh all contain documentation that:

(A) The EGU is using clean fuels to the maximum extent po ssible to bring the EGU and PM control device up to the temperature necessary to alleviate or prevent the identified safety issues prior to the combust ion of primary fuel in the EGU;Attachment C

- Page 8 of 24 (B) The EGU has explicitly followed the manufacturer's procedures to

all eviate or prevent t he identified safety issue; and

(C) Identifies with specificity the details of the manuf acturer's statement of

concern.

(vi) The request shall specify the other work practice standards the EGU owner or operator will take to limit HAP e missions during startup periods and shutdown periods to ensure a control level consistent with the work practi ce 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. C ONTINUOUS 

### C OMPLIANCE 

### R EQUIREMENTS

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

- of

control 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

mon itoring 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 otherwi se 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 syste m 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 deviati on 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 f or the pur pose 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 fo r 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)]

C ontinuous compliance with the emission limitations, operating limi ts, and work practice
standards

h

. You must demonstrate continuous compliance with each emissions limit, operating limit, and work practice standard according to th e 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 SO 2 , 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, CO 2 , O 2 , 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:

Her i 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 perfo rmance tune

- ups of your EGU(s) as specified below and perfo rm 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, y ou 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 anAttachment 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 NO X 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 NO X and CO may be installed on a schedule determined by the operato r;

(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 accordan ce 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 p arameters, 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 O 2 probes and/or sensors, adjusting overfire air systems, changing s oftware 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 NO X. This optimization should be consistent with the manufacturer's specifications, if available, or best combustion engineering pract ice for the applicable burner type. NO X optimization includes burners, overfire air controls, concentric firing system improvements, neural network or combustion efficiency software, control systems calibrations, adjusting combustion zone temperature profi les, 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 tem perature profiles;

(7) While operating at full load or the predominantly operated load, measure the
concentration in the effluent stream of CO and NO X in ppm, by volume, and oxygen in volume percent, before and after the tune

- up adjustments are made (meas urements 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, NO X and O 2 monitors for this measurement. EGU's employing neural network optimization systems need only provi deAttachment 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 NO X 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 corre ctive 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 du ring 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 mus t 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 electronicall y 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 Report ing 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 requi red 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 start up 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 prov ide 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. N OTIFICATION


### , R EPORTS


### , AND 

### R ECORDS

N otifications 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 in itial 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
materia ls 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 in cluding 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 yo u 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 Notificat ion 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 o perating 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 t he 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 co mpliance, 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 you r 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 control s;

(C) Each design PM control device efficiency;

(D) The design PM emission rate from the EGU in terms of pounds PM pe r MMBtu and pounds PM per hour;

(E) The design time from start of fuel combustion to necessary conditions for
each PM control device st artup;

(F) Each design PM control device efficiency upon st artup 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

re vision to each PM control device, and each EGU revision, along with the month and year that the change occu rred;

(I) Current EGU PM producing characteristics, including, but not limite d 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 eac h 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.

R eporting 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 ele ctronically 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 cove r 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 subm it the first and subsequent compliance reports according to the dates the permi tting 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 i nstance of startup or shutdown:

(i) Include t he 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 record ed 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 SO 2 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 40Attachment 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 pursuan t 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
emissio n 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 af fect 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 (C EDRI) 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 confiden tial 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 cle arly 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 paragra ph. 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 (SO 2 , 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 (E RT) (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 informatio n (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 erro r 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 met als 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). Yo u 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 operatin g 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 4 0 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 su bject 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 PD F 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 fil e:

(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 Fac ility Registry System (FRS) ID;

(iii) The EGU (or EGUs) to which the report applies. Report the EGU IDs as they

appe ar 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 pl an require d 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 id entification 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) o r 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 CS00 1,” or “multiple stack MS001 ”);

(vii) The rule citation (e.g., 40 CFR § 63.10031(f)(1), § 63.10031(f)(2), etc.) for which

th e 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) T he 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)]

R ecords 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 recor ds as to how the operations that produced the fuel satisfies the definition of processing in 40 CFR 241.2. If the fuel received a non

waste determination pursuant to the petition process submitted under 40 CFR 241.3(c), you must keep a record which documen ts 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 un it 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 th e past

ye ar.

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) R ecords of the occurrence and durati on of each startup or shutdown;

(2) R ecords of the determination of the maximum clean fuel capacity for each EGU;

(3) R ecords of the determination of the maximum hourly clean fuel heat input and of the hourly clean fu el heat input for each EGU; and

(4) R ecords 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 an d 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)]



### T ABLES TO 

### S UBPART 

### UUUUU OF 

### P ART 

### 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

- fire d, or solid oil

derived 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 f or 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 scr ubber 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)

.

Fo r 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 w ithin one hour of adding coal, residual oil, or solid oil

derived 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 applicabl e 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 t he 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 co mply 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 period s, 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 c oncerning 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 oil

derived 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 con trol 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 o peration 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, asAttachment 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 spec ified 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

. . . Using 2

. . .

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 emi ssions

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 (SO 2 ) SO 2 CEMS a. 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, S O 2 , 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 prac tice 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 Op erating 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
deviation s 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
dur ing which the CMSs, including continuous emissions monitoring system, and operating parameter monitoring systems, were out

- of

control as specified in 40 CFR § 63 .8(c)(7), a statement that there were no periods during which the CMSs were out

- of

- control duri ng 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 inAttachment C

- Page 24 of 24 40 CFR § 63 .8(c)(7), the report must contain the information in 40 CFR § 63 .10031(e)