the navajo nation2015/09/04 · two (2) conveyors to the coal silos for boiler u3 1,500 tons/hr...

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 [email protected]

www.navajonationepa.org/airquality.html

TITLE V PERMIT TO OPERATE

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

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

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

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

ACTION/STATUS: PART 71 OPERATING PERMIT RENEWAL ISSUANCE

Robert K. Talbot, Plant Manager

Navajo Generating Station

P.O. Box 850

Page, Arizona 86040

Re: Issuance of Title V Operating Permit Renewal to Navajo

Generating Station

Dear Mr. Talbot:

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

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

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

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

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

with the permit conditions listed in this permit.

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

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

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

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

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

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

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

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

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

Date Dr. Donald Benn

Executive Director

Navajo Nation Environmental Protection Agency

THE NAVAJO NATION RUSSELL BEGAYE PRES I DE NT

JONATHAN NEZ VICE PRESIDENT

mailto:[email protected]

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Abbreviations and Acronyms

Administrator Administrator of the U.S. EPA

AR Acid Rain

ARP Acid Rain Program

BART Best Available Retrofit Technology

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

CEMS Continuous Emission Monitoring System

CFR Code of Federal Regulations

COMS Continuous Opacity Monitoring System

DC Dust Collector

ESP Electro Static Precipitator

FGD Flue Gas Desulfurization

gal gallon

HAP Hazardous Air Pollutant

hr hour

lb pound

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

MACT Maximum Achievable Control Technology

MVAC Motor Vehicle Air Conditioner

Mg megagram

MMBtu million British Thermal Units

MW Megawatts

mo month

NESHAP National Emission Standards for Hazardous Air Pollutants

NMHC Nonmethane Hydrocarbons

NNEPA Navajo Nation Environmental Protection Agency

NNOPR Navajo Nation Operating Permit Regulations

NOX Nitrogen Oxides

NSPS New Source Performance Standards

NSR New Source Review

PM Particulate Matter

PM-10 Particulate matter less than 10 microns in diameter

ppm parts per million

PSD Prevention of Significant Deterioration

PTE Potential to Emit

QIP Quality Improvement Plan

RHR Regional Haze Rule

RMP Risk Management Plan

SNAP Significant New Alternatives Program

SO2 Sulfur Dioxide

US EPA United States Environmental Protection Agency

VCA Voluntary Compliance Agreement

VOC Volatile Organic Compounds

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TABLE OF CONTENTS

Cover Page

Abbreviations and Acronyms

I. Source Identification

II. Requirements for Specific Units

A. Federal Implementation Plan Requirements

B. PSD Permit Requirements

C. Acid Rain Requirements

D. Visibility Federal Implementation Plan Requirements

E. NSPS General Provisions

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

Requirements

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

Processing Plants, 40 CFR Part 60, Subpart OOO

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

Part 60, Subpart IIII Requirements

I. NESHAP General Provisions

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

Part 63, Subpart UUUUU Requirements

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

40 CFR Part 63, Subpart DDDDD Requirements

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

Subpart ZZZZ Requirements

M. PM CEM Requirements

N. CAM Requirements

O. Requirements for Reagent Handling Systems

P. Operational Flexibility

III. Facility-Wide or Generic Permit Conditions

A. Testing Requirements

B. Recordkeeping Requirements

C. Reporting Requirements

D. Protection of Stratospheric Ozone

E. Asbestos from Demolition and Renovation

F. Compliance Schedule

IV. Title V Administrative Requirements

A. Fee Payment

B. Blanket Compliance Statement

C. Compliance Certifications

D. Duty to Provide and Supplement Information

E. Submissions

F. Severability Clause

G. Permit Actions

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H. Administrative Permit Amendments

I. Minor Permit Modifications

J. Group Processing of Minor Permit Amendments

K. Significant Modifications

L. Reopening for Cause

M. Property Rights

N. Inspection and Entry

O. Emergency Provisions

P. Transfer of Ownership or Operation

Q. Off Permit Changes

R. Permit Expiration and Renewal

S. Additional Permit Conditions

T. Part 71 Permit Enforcement

Attachment A – Dust Control Plan

Attachment B – Phase II Acid Rain Permit Renewal

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

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

Notification, Recordkeeping, and Reporting Requirements

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I. Source Identification

Managing Participant Name: Salt River Project Agricultural Improvement

and Power District (SRP)*

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

Phoenix, Arizona 85072-2025

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

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

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

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

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

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

3. Arizona Public Service Company (APS)

4. Nevada Power Company (NPC)

5. Tucson Electric Power (TEP)

Plant Name: Navajo Generating Station

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

Page, Arizona

County: Coconino, Arizona

EPA Region: 9

Reservation: Navajo Nation

Tribe: Navajo

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

Barbara Cenalmor Phone: (602) 236-2322

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

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

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

Tennille Begay Phone: (928) 729-4248

SIC Code: 4911

AFS Plant Identification Number: 04-005-N0423

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

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Significant Emission Units:

Unit ID/

Stack ID Unit Description

Maximum

Capacity

Commenced

Construction

Date

Control Method

U1/

Stack S1

One (1) pulverized coal-fired boiler,

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

equipped with SO2, NOX, CO, and PM CEMS

and a COMS.

7,410 MBtu/hr;

750 Net MW 1970

ESP1; FGD system

SCBR1 (1999);

LNB/SOFA*(2011);

Sorbent Injection (2015)

U2/

Stack S2




and a COMS.

7,410 MBtu/hr;

750 Net MW 1970

ESP2; FGD system

SCBR2 (1998);

LNB/SOFA*(2010);


U3/

Stack S3




and a COMS.

7,410 MBtu/hr;

750 Net MW 1970

ESP3; FGD system

SCBR3 (1997);

LNB/SOFA*(2009);


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;


Coal Handling Operations

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

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

(total) 1970 wet suppression

BC-1 through

BC-4 Four (4) conveyors to the yard surge bin

1,800 tons/hr

(each) 1970 DC-8

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

BFD-5A,

BC-5 Two (2) reclaim conveyors

1,800 tons/hr

(each) 1970 DC-8

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

BC-6A through

BC-6C Three (3) conveyors to the stacker/reclaimer

1,800 tons/hr

(each) 1970

wet suppression/

enclosure

BC-7 One (1) conveyor to the emergency reclaim

hopper 1,500 tons/hr 1970 wet suppression

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

BC-8A,

BC-8B Two (2) conveyors to plant surge bin

1,500 tons/hr

(each) 1970 DC-8

BC-8AS,

BC-8BS Two (2) screens

1,500 tons/hr

(each) 1970 DC-8

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

BC-9A,

BC-9B

Two (2) conveyors to the coal silos for boilers

U1 and U2

1,500 tons/hr

(each) 1970 DC-5

BC-10A,

BC-10B

Two (2) conveyors to the coal silos for boiler

U3

1,500 tons/hr

(each) 1970 DC-5

CC-1A through

CC-9A; CC-1B

through CC-9B

Three (3) enclosed cascading conveying systems

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

U3

1,500 tons/hr

(each) 1970

DC-1 through DC-4,

DC-6, and DC-7

Silos 1A through

1G Seven (7) storage silos for boiler U1

3,000 tons/hr

(each) 1970

DC-1, DC-2, and

baghouse PR-1.

Silos 2A through


3,000 tons/hr

(each) 1970

DC-3, DC-4, and

baghouse PR-2.

Silos 3A through


3,000 tons/hr

(each) 1970

DC-6, DC-7, and

baghouse PR-3.

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Unit ID/


Maximum

Capacity

Commenced

Construction

Date

Control Method

CS Outdoor coal storage piles 3,300 tons/hr


Limestone Handling System Associated with the FGD Systems

Unloading Bay

A and B Two (2) truck unloading operations

38 tons/hr

(each) 1997 N/A

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

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

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

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

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

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

O-LSH-SILO-A

and B Two (2) limestone storage silos

300 tons/hr

(each) 1997 DC-11

O-LSP-FDR-A

and B

Two (2) enclosed feeders to the slurry

preparation system

36 tons/hr

(each) 1997 N/A

O-LSP-CNV-A

and B Two (2) enclosed cleanout conveyors

5 tons/hr

(each) 1997 N/A

O-LSP-MILL-A

and B Two (2) ball mills

36 tons/hr

(each) 1997 N/A

LS Limestone storage piles 600 tons/hr


Fly Ash Handling System

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

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

Silo 1 and 2

Loading

Two (2) partially enclosed fly ash truck loading

operations

38 tons/hr

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

DWB-A through

DWB-F

Six (6) bottom ash truck loading operations.

The bottom ash is processed in a wet form

46 tons/hr

(each) 1970 wet suppression

Soda Ash/Lime Handling Systems

SAB-1A, 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


Reagent Handing Systems

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

PAC Silo B PAC storage silo 40 tons 2015 integral baghouse

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

Fugitive-CaBr2 Truck traffic on unpaved roads for Calcium

Bromide delivery 365 VMT/yr** 2015 water spray

Miscellaneous Operations

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

(total) 1970 N/A

TR Fugitive emissions from unpaved roads N/A 1970 wet suppression Note: (*) LNB/SOFA = Low-NOX burner (LNB) and Separated Overfire Air (SOFA) system. (**) VMT = vehicle miles traveled.

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II. Requirements for Specific Units

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

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

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

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

[40 CFR § 49.5513(c)]:

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

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

taken out of service.

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

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

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

independently and objectively evaluated in a judicial or administrative

proceeding. 40 CFR § 49.5513provides an affirmative defense to

actions for penalties brought for excess emissions that arise

during certain malfunction episodes.

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

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

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

maintenance, careless operation, or any other preventable upset

condition or preventable equipment breakdown shall not be

considered malfunctions. An affirmative defense is not available if

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

relevant ambient air quality standard that could be attributed to the

emitting source.

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

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

unit as determined by 40 CFR Part 75.

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

pneumatic material transferring, any baghouse or other control devices

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

stationary point of dust that may be observed in conformance with

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

f. Regional Administrator means the Regional Administrator of the

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

representative.

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

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to the time when the electrostatic precipitator is sufficiently heated such

that the temperature of the air preheater inlet reaches 400 degrees

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

procedures shall include energizing the electrostatic precipitator prior to

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

affirmative defense to actions for penalties brought for excess emissions

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

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

relevant ambient air quality standard that could be attributed to the

emitting source.

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

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

precipitator shall be maintained in service until boiler fans are

disengaged. 40 CFR § 49.5513 provides an affirmative defense to

actions for penalties brought for excess emissions that arise during

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

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

ambient air quality standard that could be attributed to the emitting

source.

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

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

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

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

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

U3in excess of 1.0 pound per million British thermal units

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

basis.

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

discharge of particulate matter into the atmosphere in excess of 0.060

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

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

collecting a minimum sample of 30 dry standard cubic feet.

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

methods for controlling dust from the coal handling and storage

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

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

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

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

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

truck loading or unloading operation, or railcar unloading station, as

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

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

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

atmosphere exhibiting greater than 20% opacity, excluding condensed

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

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

transition periods.

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

a. The permittee shall maintain and operate Continuous Emissions

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

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

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

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

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

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

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

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

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

Appendix A.

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

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

permittee shall conduct mass emissions tests for sulfur dioxide, nitrogen

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

monitors shall be performed in accordance with 40 CFR Part 58,

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

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

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

annually to the Regional Administrator. All particulate matter samplers

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

particulate sampling schedule.

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

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

violation of the Clean Air Act or this section.

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

observer shall conduct a weekly visible emission observation for the

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

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

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

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

any corrective actions taken shall be noted in a log.

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

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

communications to the Regional Administrator required by this section shall be

submitted to the Director, Navajo Nation Environmental Protection Agency,

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

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

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

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

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

shall:

a. Comply with the notification and recordkeeping requirements for testing

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

submitted to the Regional Administrator and postmarked within 60 days

of testing.

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

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

Environmental Protection Agency Regional Administrator by

telephone, in writing or by email ([email protected]) within one business

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

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

This notification shall include the following information:

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

excess emissions occurred;

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


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the applicable emissions limitation and the operating data and

calculations used in determining the magnitude of the excess

emissions;

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

emissions;

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

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

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

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

prevent the recurrence of such malfunction; and

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

emissions.

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

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

monitor operated in accordance with this regulation. The notification to

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

exceedance and the pollutant and concentration of the exceedance.

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

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

regulation which such excess emissions or malfunction may cause. The

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

containing the following information:

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

(ii) The pollutant and concentration of the exceedance;

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

during the exceedance;

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

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

during the exceedance; and

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

to prevent future exceedances.

d. Submit quarterly excess emissions reports for sulfur dioxide and

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

assessment report to the Regional Administrator no later than 30 days

after each calendar quarter. The permittee shall complete the excess

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

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

condensed water vapor in the stack does not constitute a reportable

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

interfered with COMs readings should be summarized in the 40 CFR § §

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60.7 (c) report.

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

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

credible evidence or information relevant to whether a source would have

been in compliance with applicable requirements if the appropriate

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

submitting compliance certifications.

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

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

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

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

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

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

practicable.

7. Enforcement [40 CFR § 49.5513(i)]:

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

or information relevant to whether a source would have been in

compliance with applicable requirements if the appropriate

performance or compliance test had been performed can be used to

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

applicable standard.

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

emission limits or requirements for opacity and particulate matter shall not

apply provided that:

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

good practice for minimizing emissions, and the permittee uses best

efforts regarding planning, design, and operating procedures

to meet the otherwise applicable emission limit;

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

mode are minimized to the maximum extent practicable; and

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

are documented by properly signed, contemporaneous

operating logs, or other relevant evidence.

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

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

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

defense in an enforcement action seeking penalties if the permittee has

met with all of the following conditions:

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

failure of process or air pollution control equipment and did not

result from inadequate design or construction of the process

or air pollution control equipment;

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

from improper operation or maintenance procedures;

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

indicative of inadequate design, operation, or maintenance;

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

malfunction, and the amount and duration of the excess emissions

caused by the malfunction were minimized to the maximum extent

practicable;

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

excess emissions on ambient air quality;

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

all possible; and

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

documented by properly signed, contemporaneous operating logs,

or other relevant evidence.

8. Regional Haze Best Available Retrofit Technology (BART)

Requirements [40 CFR § 49.5513(j)]:

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

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

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

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

emission reductions sufficient to maintain total cumulative NOX

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

CFR § 49.5513(j)(3)]

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

the applicable Alternative for ensuring compliance with the 2009-2044

NOx Cap. [40 CFR § 49.5513(j)(4)(i)]

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

22, 2044 or the date on which the permittee ceases conventional 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 emissions

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

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

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

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

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

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

available within 30 days of the submittal deadline associated with the

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

49.5513(j)(4)(ii)]

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

application to revise its existing Part 71 Operating Permit to incorporate

the requirements and emission limits of the applicable Alternative to

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

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

must incorporate practically enforceable limits for NOX of 0.24

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

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

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

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

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

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

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

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

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

CEMS [40 CFR § 49.5513(j)(5)]:

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

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

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

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

used to determine compliance with the emission limitations for

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

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

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

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

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

hours, on an annual basis.

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

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

requirements, relative accuracy test audits shall be calculated for

both the NOX pounds per hour measurement and the heat input

measurement. The calculation of NOX pounds per hour and heat

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input relative accuracy shall be evaluated each time the CEMS

undergo relative accuracy testing.

g. The permittee shall maintain the following records 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 NOX and heat input for each

hour.

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

emissions measuring systems including, but not limited to, any

records required by 40 CFR part 75.

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

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

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

49.5513(j)(8)(i)]

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

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

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

consistent with good air pollution control practices for minimizing

emissions. [40 CFR § 49.5513(j)(10)]

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

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

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

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

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

IX.B]

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

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

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

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

average.

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

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

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

AZ 08-01A, Condition IX.D]

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

08-01A, Condition IX.E]

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

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

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

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

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

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

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

requirements of 40 CFR Part 75.

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

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

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

the requirements of 40 CFR Part 75.

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

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

period.

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

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

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

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

Condition IX.G]

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

and U3 on a monthly basis.

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

and U3 on a monthly basis.

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

and emissions calculations for emissions limits required in Condition

II.B.1.

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

occurrence and duration of any startup, shutdown or malfunction,

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performance testing, evaluations, calibrations, checks, adjustments,

maintenance, duration of any periods during which a continuous

monitoring system or monitoring device is inoperative, and emission

measurements.

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

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

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

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

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

preventive measures adopted;

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

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

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

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

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

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

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

CEMS, exceeds the maximum emission limits set forth in Condition

II.B.1.

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

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

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

the applicable emission limit.

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

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

renewal (see Attachment B).

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

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

CFR § 52.145(d)(1)]:

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

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

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

limitation in Condition II.D.2 of this permit.

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

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

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

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

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

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

combusted in the unit.

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

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

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

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

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

as follows [40 CFR § 52.145(d)(3)]:

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

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

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

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

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

measured by the megawatt-hour meter for the unit.

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

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

60 in effect on October 3, 1991.

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

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

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

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

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

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

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

days will be used for compliance determinations.

e. Sum, for all affected units, the products of the daily SO2 emission 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.

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

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

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

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

dividing the sum of the products determined according to Condition

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

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

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

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

of this permit.

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

operate continuous emission monitoring systems to determine compliance with

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

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

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

comply with the quality assurance procedures for continuous emission monitoring

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

§ 52.145(d)(4)].

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

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

52.145(d)(5)]:

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

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

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

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

energy generated in megawatt-hours.

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

effect on October 3, 1991.

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

mail sent to [email protected] within one business day of any outage of

the control system needed for compliance with the emission limitation in

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

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

and justifying the amount of time taken for the repairs.

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

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

52.145(d)(6)].

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

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

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

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

prevented by good engineering practices will be excluded from the compliance

determination. Events which are the consequence of lack of appropriate

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

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

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

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

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

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

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

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

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

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

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

the Navajo Generating Station which accommodates the maintenance

requirements for the other generating facilities on the Navajo Generating Station

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

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

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

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

Western Electric Coordinating Council of the North American Electric Reliability

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

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

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

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

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

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

10. Exceptions for maintenance scheduling. The permittee shall conduct a full 6 unit-

weeks of maintenance in accordance with the plan required in Condition II.D.9 of

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

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

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

52.145(d)(13)]:

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

the year covered by the plan;

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

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

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

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

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

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

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

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

March 15 period, and necessary periodic maintenance occurs during the

period of forced outage.

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

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

nevertheless conduct that amount of scheduled maintenance that is not precluded

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

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

15 period. [40 CFR § 52.145(d)(13)]

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

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

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

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

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

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

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

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

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

Director, Air Division (Attn: AIR-1)

EPA Region IX

75 Hawthorne Street

San Francisco, CA 94105

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

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

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

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

60.7(b)].

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

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

(Information submitted voluntarily to the Administrator for the purposes of

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

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

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

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

CFR § 60.11(c)].

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

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

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

consistent with good air pollution control practice for minimizing emissions.

Determination of whether acceptable operating and maintenance procedures are

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

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

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

60.11(d)].

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

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

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

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

been in compliance with applicable requirements if the appropriate performance

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

b. Exhibit greater than 7 percent opacity.

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

discharge any fugitive emissions which exhibit greater than 10 percent opacity

[40 CFR § 60.672(b)].

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

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

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

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

60.672(d)].

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

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

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

facility or facilities must comply with the following emission limits:

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

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

60.672(e)(1)].

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

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

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

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

opacity [40 CFR § 60.672(f)].

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

System, 40 CFR Part 60, Subpart OOO

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

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

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

the permittee shall conduct performance tests for particulate matter emissions

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

is operating in accordance with 40 CFR § 60.675.

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

shall record and maintain the following records:

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

b. the unit ID number.

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

they were observed continuously or intermittently.

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

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

Part 60, Subpart IIII Requirements

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

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

Compression Ignition Internal Combustion Engines”):

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

60.4205(c)]:

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

b. 0.2 g/KW-hr or 0.15 g/HP-hr for PM emissions.

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

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

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

CFR § 60.4207(b)]

a. 15 ppm sulfur content; and

b. Cetane index or aromatic content, as follows:

(i) A minimum cetane index of 40; or

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

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

60.4211(a)]:

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

the manufacturer's emission-related written instructions;

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

manufacturer; and

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

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

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

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

specifications. [40 CFR § 60.4211(c)]

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

the following [40 CFR § 60.4211(f)]:

a. No use time limit for emergency situations.

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

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

situations:

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

are recommended by federal, state or local government, the

manufacturer, the vendor, the regional transmission organization or

equivalent balancing authority and transmission operator, or the

insurance company associated with the engine.

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

Coordinator under the North American Electric Reliability

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

and Energy Emergencies (incorporated by reference into 40 CFR §

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

Coordinator, has declared an Energy Emergency Alert Level 2 as

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

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

percent or greater below standard voltage or frequency.

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

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

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

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

as part of a financial arrangement with another entity.

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

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

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

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

compliance with either an extension of compliance or an exemption from

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

extension of compliance can be granted by the Administrator under this

part.

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

as required by 40 CFR Part 63.

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

equipment, or process to conceal an emission that would otherwise

constitute noncompliance with a relevant standard. Such concealment

includes, but is not limited to:

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

based on the concentration of a pollutant in the effluent discharged

to the atmosphere; or

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

standard for visible emissions.

2. The permittee shall follow the preconstruction review and notification

requirements specified in 40 CFR § 63.5.

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

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

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

standard.

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

63.9.

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

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

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

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

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

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

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

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

storage. [40 CFR § 63.10(b)(1)]

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

Part 63, Subpart UUUUU Requirements

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

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

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

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

Letter Dated January 27, 2014]:

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

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

bromide application and powder activated carbon (PAC) injection system

to control the Hg emissions.]

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

mercury provisions of this NESHAP.

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

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

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

Approval Letter Dated January 27, 2014].

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

days after the final compliance deadline describing the chosen control technology

and demonstrating that it is meeting the requirements under this NESHAP

[Extension Approval Letter Dated January 27, 2014].

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

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

63.10000(a)]:

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

lb/MMBtu or 0.3 lb/MWh.

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

lb/MWh.

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

or 0.013 lb/GWh.

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

standards: [40 CFR § 63.9991(a)(1)]

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

each 48 calendar months if neural network combustion optimization

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

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

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

Attachment C for details]

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

Condition II.J.4 using the following methods:

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

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

operation in late 2015.

b. SO2: Operation of the existing SO2 CEMS.

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

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

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

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

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

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

40 CFR Part 63, Subpart DDDDD Requirements

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

accordance with 40 CFR Part 63, Subpart DDDDD (“National Emission Standards for

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

Boilers and Process Heaters”):

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

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

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

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

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

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

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

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

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

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

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

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

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

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

into the storage vessel or process equipment;

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

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

the manufacturer's specifications, if available;

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

ensure that it is correctly calibrated and functioning properly (the

permittee may delay the inspection until the next scheduled unit

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

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

inspection;

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

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

requirement to which the unit is subject;

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

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

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

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

Measurements may be taken using a portable CO analyzer; and

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

report containing the information specified below:

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(i) The concentrations of CO in the effluent stream in parts per

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

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

the boiler or process heater; and

(ii) A description of any corrective actions taken as a part of the 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 records:

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

Part 63, Subpart DDDDD, including all documentation supporting any

Initial Notification or Notification of Compliance Status or semiannual

compliance report, according to the requirements in 40 CFR §

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

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

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

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

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

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

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

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

CFR § 63.7555(j)].

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

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

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

shall include the following: [40 CFR § 63.7550]

(a) Company and Facility name and address;

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

limitations;

(c) Date of report and beginning and ending dates of the reporting period;

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(d) The total operating time during the reporting period;

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

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

unscheduled unit shutdown.

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

63, Subpart ZZZZ Requirements

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

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

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

Stationary Reciprocating Internal Combustion Engines”):

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

for Stationary Compression Ignition Internal Combustion Engines, 40 CFR Part

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

NESHAP [40 CFR § 63.6590(c)].

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

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

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

comes first;

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

comes first, and replace as necessary;

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

comes first, and replace as necessary; and

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

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

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

emission limitations apply.

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

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

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

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

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

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

5. The operation hours for each of the emergency generators EG2, EG3, and NPG-

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

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a. No use time limit for emergency situations.

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

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

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

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

are recommended by federal, state or local government, the

manufacturer, the vendor, the regional transmission organization or

equivalent balancing authority and transmission operator, or the

insurance company associated with the engine.

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

Coordinator under the North American Electric Reliability

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

and Energy Emergencies (incorporated by reference into 40 CFR §

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

Coordinator, has declared an Energy Emergency Alert Level 2 as

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

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

percent or greater below standard voltage or frequency.

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

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

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

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

as part of a financial arrangement with another entity.

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

EG3, and NPG-746 [40 CFR § 63.6655]:

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

63.6655(e)].

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

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

hours are spent for emergency operation, including what classified the

operation as an emergency and how many hours are spent for 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)].

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II.M. PM CEMS Requirements

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

shall comply with the following requirements for the PM CEMS:

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

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

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

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

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

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

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

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

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

U2, and U3:

1. Monitoring

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

64.6(c)(1)(i)]

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

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

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

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

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

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

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

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

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

for more than 1 hour.

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

follows: [40 CFR § 64.6(c)(1)(ii)]

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

be recorded on a continuous basis by the BHA WinDAC Data

Acquisition and Control Software and supplemented with

operating logs; these status bits indicate the number of

chambers/fields that are operational in the ESPs.

(ii) The wet limestone scrubber spray level signal shall be recorded on

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a continuous basis by a data acquisition handling system.

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

measure the temperature of the exhaust and be recorded as an

hourly average by a data acquisition system.

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

wet limestone scrubber is operational shall be recorded on a

continuous basis by a data acquisition handling system.

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

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

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

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

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

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

64.6(c)(1)(iii)]

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

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

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

practices for minimizing emissions.

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

of service.

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

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

scrubber associated with the same boiler.

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

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

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

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

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

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

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

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

boiler unit.

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

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each boiler unit.

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

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

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

equipment. [40 CFR § 64.7(b)]

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

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

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

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

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

recorded during monitoring malfunctions, associated repairs, and required quality

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

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

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

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

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

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

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

malfunctions. [40 CFR § 64.7(c)]

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

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

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

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

operation as expeditiously as practicable in accordance with good air

pollution control practices for minimizing emissions. The response shall

include minimizing the period of any startup, shutdown or malfunction

and taking any necessary corrective actions to restore normal operation

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

exceedance (other than those caused by excused startup or shutdown

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

recording that operations returned to normal without operator action (such

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

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

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

standard, as applicable.

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

response to an excursion or exceedance will be based on information

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

review of operation and maintenance procedures and records, and

inspection of the control device, associated capture system, and the

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process.

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

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

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

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

indicator ranges or designated conditions, the permittee shall promptly notify

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

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

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

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

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

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

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

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

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

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

64.8(a)]

9. Reporting and Recordkeeping Requirements [40 CFR § 64.9]

a. A report for monitoring under this permit shall include, at a minimum, the

information required under Condition III.C of this permit and the

following information, as applicable [40 CFR § 64.9(a)(2)]:

(i) Summary information on the number, duration and cause

(including unknown cause, if applicable) of excursions or

exceedances, as applicable, and the corrective actions taken;

(ii) Summary information on the number, duration and cause

(including unknown cause, if applicable) for monitor downtime

incidents (other than downtime associated with zero and span or

other daily calibration checks, if applicable); and

(iii) A description of the actions taken to implement a QIP during the

reporting period as specified in 40 CFR § 64.8. Upon completion

of a QIP, the permittee shall include in the next summary report

documentation that the implementation of the plan has been

completed and reduced the likelihood of similar levels of

excursions or exceedances occurring.

b. The permittee shall comply with the recordkeeping requirements specified

in Condition III.B of this permit. The permittee shall maintain records of

monitoring data, monitor performance data, corrective actions taken, any

written QIP required pursuant to 40 CFR § 64.8 and any activities

undertaken to implement a QIP, and other supporting information required

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to be maintained under 40 CFR Part 64 (such as data used to document the

adequacy of monitoring or records of monitoring maintenance or

corrective actions) [40 CFR § 64.9(b)(1)].

c. Instead of paper records, the permittee may maintain records on

alternative media, such as microfilm, computer files, magnetic tape disks,

or microfiche, provided that the use of such alternative media allows for

expeditious inspection and review, and does not conflict with other

applicable recordkeeping requirements [40 CFR § 64.9(b)(2)].

II.O. Requirements for Reagent Handling Systems [40 CFR §§ 49.151-161]

Pursuant to Tribal Minor NSR Permit #T-0004-NN, issued on August 26, 2015, the

permittee shall comply with the following requirements for the powdered activated

carbon (PAC) and calcium bromide handling systems:

1. Vehicle miles travel (VMT) for truck traffic associated with the delivery of PAC

shall not exceed 30 VMT per 12-month period.

2. VMT for truck traffic associated with the delivery of calcium bromide shall not

exceed 365 VMT per 12-month period.

3. The permittee shall monitor and maintain records on a calendar month basis of

each PAC deliver, the VMT of each delivery, and determine the 12-month rolling

total.

4. The permittee shall monitor and maintain records on a calendar month basis of

each calcium bromide deliver, the VMT of each delivery, and determine the 12-

month rolling total.

5. At least once during each calendar week, the permittee shall perform a visible

emissions survey for each PAC silo (Silos A and B). The survey shall be

performed during daylight hours by an individual trained in EPA Method 22

while the equipment is in operation. If visible emissions are detected during the

survey, the permittee shall take corrective action so that within 24 hours no visible

emissions are detected.

II.P. Operational Flexibility

1. Clean Air Act Section 502(b)(10) Changes [40 CFR § 71.6(a)(13)(i)] [NNOPR

§ 404(A)]

a. The permittee may make Clean Air Act Section 502(b)(10) changes

without applying for a permit revision if those changes do not cause the

facility to exceed emissions allowable under this permit (whether

expressed as a rate of emissions or in terms of total emissions) and are not

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

does not include:

(i) Changes that would violate applicable requirements (as defined in

40 CFR § 71.2, NNOPR § 102(11)); or

(ii) Changes that would contravene federally enforceable permit terms

and conditions that are monitoring (including test methods),

recordkeeping, reporting, or compliance certification requirements.

b. For each proposed Clean Air Act Section 502(b)(10) change, the permittee

shall provide written notification to the Director and the Administrator at

least 7 days in advance of the proposed change. Such notice shall state

when the change will occur and shall describe the change, any resulting

emissions change, and any permit terms or conditions made inapplicable

as a result of the change. The permittee shall attach each notice to its copy

of this permit.

c. Any permit shield provided in this permit shall not apply to any change

made pursuant to Condition II.P.1.

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III. Facility-Wide or Generic Permit Requirements

Conditions in this section of the permit (Section III) apply to all emissions units located at

the facility [See 40 CFR § 71.6(a)(1)].

III.A. Testing Requirements [40 CFR § 71.6(a)(3)]

In addition to the unit-specific testing requirements derived from the applicable

requirements for each individual unit contained in Section II of this permit, the permittee

shall comply with the following generally applicable testing requirements as necessary to

ensure that the required tests are sufficient for compliance purposes:

1. Submit to NNEPA a source test plan 30 days prior to any required testing. The

source test plan shall include and address the following elements:

1.0 Purpose of the Test

2.0 Source Description and Mode of Operation During Test

3.0 Scope of Work Planned for Test

4.0 Schedule/Dates

5.0 Process Data to be Collected During Test

6.0 Sampling and Analysis Procedures

6.1 Sampling Locations

6.2 Test Methods

6.3 Analysis Procedures and Laboratory Identification

7.0 Quality Assurance Plan

7.1 Calibration Procedures and Frequency

7.2 Sample Recovery and Field Documentation

7.3 Chain of Custody Procedures

7.4 QA/QC Project Flow Chart

8.0 Data Processing and Reporting

8.1 Description of Data Handling and QC Procedures

8.2 Report Content

2. Unless otherwise specified by an applicable requirement or permit condition in

Section II, all source tests shall be performed at maximum operating rates (90% to

110% of device design capacity).

3. Only regular operating staff may adjust the processes or emission control device

parameters within two (2) hours before or during a compliance source test. All

adjustments must be logged and a copy of the log submitted with the test report.

No adjustments are to be made within two (2) hours before the start of the tests or

during a test, if those adjustments are a result of consultation before or during the

tests with source testing personnel, equipment vendors, or consultants. Such

adjustments may render the source test invalid.

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4. During each test run and for two (2) hours prior to the test and two (2) hours after

the completion of the test, the permittee shall record the following information:

a. Visible emissions or COMS data; and

b. All parametric data which is required to be monitored in Section II for the

emission unit being tested.

5. Each source test shall consist of at least three (3) valid test runs and the emission

results shall be reported as the arithmetic average of all valid test runs and in the

terms of the emission limit. There must be at least 3 valid test runs, unless

otherwise specified.

6. Source test reports shall be submitted to NNEPA and U.S. EPA within 60 days of

completing any required source test.

III.B. Recordkeeping Requirements [40 CFR § 71.6(a)(3)(ii)]

In addition to the unit-specific recordkeeping requirements derived from the applicable

requirements for each individual unit and contained in Section II, the permittee shall

comply with the following generally applicable recordkeeping requirements:

1. The permittee shall keep records of required monitoring information that include

the following:

a. The date, place, and time of sampling or measurements;

b. The date(s) analyses were performed;

c. The company or entity that performed the analyses;

d. The analytical techniques or methods used;

e. The results of such analyses; and

f. The operating conditions existing at the time of the sampling or

measurement.

2. The permittee shall retain records of all required monitoring data and support

information for a period of at least 5 years from the date of the monitoring

sample, measurement, report, or application. Support information includes all

calibration and maintenance records, all original strip-chart recordings for

continuous monitoring instrumentation, and copies of all reports required by this

permit.

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3. The permittee shall maintain a file of all measurements, including continuous

monitoring system, monitoring device, and performance testing measurements; all

continuous monitoring system performance evaluations; all continuous

monitoring system or monitoring device calibration checks; adjustments and

maintenance performed on these systems or devices; and all other information

required by 40 CFR Part 60 recorded in a permanent form suitable for inspection.

The file shall be retained for at least five years following the date of such

measurements, maintenance, reports and records [40 CFR § 71.6(a)(3)(ii), 40

CFR § 60.7(f)].

III.C. Reporting Requirements [40 CFR § 71.6 (a)(3)(iii)]

1. The permittee shall submit to NNEPA and EPA Region 9 reports of any

monitoring required under 40 CFR § 71.6(a)(3)(i)(A), (B), or (C) each six month

reporting period from January 1 to June 30 and from July 1 to December 31. All

reports shall be submitted to NNEPA and US EPA and shall be postmarked by the

30th day following the end of the reporting period. All instances of deviations

from permit requirements must be clearly identified in such reports. All required

reports must be certified by a responsible official consistent with Condition

III.C.4 of this permit.

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

(i) The company name and address.

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

(iii) The emissions unit or activity being monitored.

(iv) The emissions limitation or standard, including operational

requirements and limitations (such as parameter ranges), specified

in the permit for which compliance is being monitored.

(v) All instances of deviations from permit requirements, including

those attributable to upset conditions and exceedances as defined

under 40 CFR § 64.1, and the date on which each deviation

occurred.

(vi) If the permit requires continuous monitoring of an emissions limit

or parameter range, the report must include the total operating time

of the emissions unit during the reporting period, the total duration

of excess emissions or parameter exceedances during the reporting

period, and the total downtime of the continuous monitoring

system during the reporting period.

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(vii) If the permit requires periodic monitoring, visual observations,

work practice checks, or similar monitoring, the report shall

include the total time when such monitoring was not performed

during the reporting period and at the source's discretion either the

total duration of deviations indicated by such monitoring or the

actual records of deviations.

(viii) All other monitoring results, data, or analyses required to be

reported by the applicable requirement.

(ix) The name, title, and signature of the responsible official who is

certifying to the truth, accuracy, and completeness of the report.

b. Any report required by an applicable requirement that provides the same

information described in Condition III.C.1.a.(i) through (ix) above shall

satisfy the requirement under Condition III.C.1.a.

c. "Deviation," means any situation in which an emissions unit fails to meet

a permit term or condition. A deviation is not always a violation. A

deviation can be determined by observation or through review of data

obtained from any testing, monitoring, or record keeping established in

accordance with 40 CFR §§ 71.6(a)(3)(i) and (a)(3)(ii). For a situation

lasting more than 24 hours, each 24-hour period is considered a separate

deviation. Included in the meaning of deviation are any of the following:

(i) A situation when emissions exceed an emission limitation or

standard;

(ii) A situation where process or emissions control device parameter

values indicate that an emission limitation or standard has not been

met;

(iii) A situation in which observations or data collected demonstrate

noncompliance with an emission limitation or standard or any

work practice or operating condition required by the permit.

(iv) A situation in which an exceedance or excursion, as defined in 40

CFR § 64.1, occurs.

2. The permittee shall promptly report to the NNEPA and EPA Regional Office

deviations from permit requirements, including those attributable to upset

conditions, the probable cause of such deviations, and any corrective actions or

preventive measures taken. Where the underlying applicable requirement contains

a definition of “prompt” or otherwise specifies a time frame for reporting

deviations, that definition or time frame shall govern.

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Where the underlying applicable requirement does not define prompt or provide a

timeframe for reporting deviations, reports of deviations will be submitted based

on the following schedule:

a. For emissions of a hazardous air pollutant or a toxic air pollutant (as

identified in the applicable regulation) that continue for more than an hour

in excess of permit requirements, the report must be made by telephonic,

verbal, or facsimile communication within 24 hours of the occurrence.

b. For emissions of any regulated pollutant, excluding a hazardous air

pollutant or a toxic air pollutant, that continue for more than two hours in

excess of permit requirements, the report must be made by telephonic,

verbal, or facsimile communication within 48 hours of the occurrence.

c. For all other deviations from permit requirements, the report shall be

submitted with the semi-annual monitoring report required in Condition

III.C.1 of this permit.

3. If any of the conditions in Condition III.C.2.a or b of this permit are met, the

source must notify NNEPA and US EPA by telephone, facsimile, or electronic

mail sent to [email protected] and [email protected], based on the

timetable listed. A written notice, certified consistent with Condition III.C.4 of

this permit, must be submitted within 10 working days of the occurrence. All

deviations reported under this section must also be identified in the 6-month

report required under Condition III.C.1.

4. Any application form, report, or compliance certification required to be submitted

by this permit shall contain certification by a responsible official of truth,

accuracy, and completeness. All certifications shall state that, based on

information and belief formed after reasonable inquiry, the statements and

information in the document are true, accurate, and complete.

III.D. Protection of Stratospheric Ozone [40 CFR Part 82]

1. The permittee shall comply with the standards for labeling of products using

ozone-depleting substances pursuant to 40 CFR Part 82, Subpart E:

a. All containers in which a class I or class II substance is stored or

transported, all products containing a class I substance, and all products

directly manufactured with a Class I substance being introduced into

interstate commerce must bear warning statements that comply with the

requirements in 40 CFR § 82.106(a). [40 CFR § 82.124(a)(1)(i)]

b. On January 1, 2015, or any time between May 15, 1993 and January 1,

2015 that the Administrator determines for a particular product

manufactured with or containing a class II substance that there are

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substitute products or manufacturing processes for such product that do

not rely on the use of a class I or class II substance, that reduce the overall

risk to human health and the environment, and that are currently or

potentially available, no product identified in 40 CFR § 82.102(b) may be

introduced into interstate commerce unless it bears a warning statement

that complies with the requirements of 40 CFR § 82.106, unless such

labeling is not required under 40 CFR §§ 82.106(b), 82.112(c) or (d),

82.116(a) or 82.118(a). [40 CFR § 82.124(a)(1)(ii)]

c. The placement of the required warning statement must comply with the

requirements of 40 CFR § 82.108. [40 CFR § 82.124(a)(2)(i)]

d. The form of the label bearing the required warning statement must comply

with the requirements of 40 CFR § 82.110. [40 CFR § 82.124(a)(3)(i)]

e. No person may modify, remove, or interfere with the required warning

statement except as described in 40 CFR § 82.112. [40 CFR §

82.124(a)(4)]

2. The permittee shall comply with the standards for recycling and emissions

reduction pursuant to 40 CFR Part 82, Subpart F, except as provided for motor

vehicle air conditioners (MVACs) in Subpart B [40 CFR § 82.150(b)]:

a. Persons opening appliances for maintenance, service, repair, or disposal

must comply with the required practices pursuant to 40 CFR § 82.156.

b. Equipment used during maintenance, service, repair, or disposal of

appliances must comply with the standards for recycling and recovery

equipment pursuant to 40 CFR § 82.158.

c. Persons performing maintenance, service, repair, or disposal of appliances

must be certified by an approved technician certification program pursuant

to 40 CFR § 82.161.

d. Persons disposing of small appliances, MVACs, and MVAC-like

appliances (as defined in 40 CFR § 82.152) must comply with

recordkeeping requirements pursuant to 40 CFR § 82.166.

e. Persons owning commercial or industrial process refrigeration equipment

must comply with the leak repair requirements pursuant to 40 CFR §

82.156.

f. Owners/operators of appliances normally containing 50 or more pounds of

refrigerant must keep records of when the refrigerant was purchased and

added to such appliances pursuant to 40 CFR § 82.166.

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3. If the permittee produces, transforms, destroys, imports, or exports a Class I or

Class II controlled substance, the permittee is subject to all the requirements in 40

CFR Part 82, Subpart A, Production and Consumption Controls [40 CFR §

82.1(b)].

4. If the permittee performs a service on a motor (fleet) vehicle when this service

involves ozone-depleting substance refrigerant (or regulated substitute substance)

in the MVAC, the permittee is subject to all the applicable requirements specified

in 40 CFR Part 82, Subpart B, Servicing of Motor Vehicle Air Conditioners [40

CFR § 82.30(b)].

The term "motor vehicle" as used in Subpart B does not include a vehicle in

which final assembly of the vehicle has not been completed. The term "MVAC"

as used in Subpart B does not include the air-tight sealed refrigeration system

used for refrigerated cargo or system used on passenger buses using HCFC-22

refrigerant [40 CFR § 82.32(c), (d)].

5. The permittee shall be allowed to switch from any ozone-depleting substance to

any acceptable substitute that is listed in the Significant New Alternatives

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

III.E. Asbestos from Demolition and Renovation [40 CFR Part 61, Subpart M]

The permittee shall comply with the requirements of 40 CFR §§ 61.140 through 61.157

of the National Emission Standard for Asbestos for all demolition and renovation projects

[40 CFR § 61.140].

III.F. Compliance Schedule [40 CFR §§ 71.5(c)(8)(iii) and 71.6(c)(3)]

1. For applicable requirements with which the source is in compliance, the source

will continue to comply with such requirements.

2. For applicable requirements that will become effective during the permit term, the

source shall meet such requirements on a timely basis.

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IV. Title V Administrative Requirements

IV.A. Fee Payment [NNOPR Subpart VI] [40 CFR § 71.6(a)(7) and § 71.9]

1. The permittee shall pay an annual permit fee in accordance with the procedures

outlined below. [NNOPR §§ 603(A) and (B)]

a. The permittee shall pay the annual permit fee by April 1 of each year.

b. Fee payments shall be remitted in the form of a money order or certified

check made payable to the Navajo Nation Environmental Protection

Agency.

c. The permittee shall send the fee payment to:

Navajo Nation EPA Air Quality Control Program

Operating Permit Program

P.O. Box 529

Fort Defiance, AZ 86504

2. The permittee shall submit a fee calculation worksheet form with the annual

permit fee by April 1 of each year. Calculations of actual or estimated emissions

and calculation of the fees owed shall be computed on the fee calculation

worksheets provided by US EPA. Fee payment of the full amount must

accompany each fee calculation worksheet. [40 CFR § 71.6(a)(7) and §

71.9(h)(1)]

3. The fee calculation worksheet shall be certified by a responsible official

consistent with 40 CFR § 71.5(d). [40 CFR § 71.6(a)(7) and § 71.9(h)(2)]

4. Basis for calculating annual fee:

The annual emissions fee shall be calculated by multiplying the total tons of

actual emissions of all fee pollutants emitted from the source by the applicable

emissions fee (in dollars/ton) in effect at the time of calculation. Emissions of any

regulated air pollutant that already are included in the fee calculation under a

category of regulated pollutant, such as a federally listed hazardous air pollutant

that is already accounted for as a VOC or as PM10, shall be counted only once in

determining the source’s actual emissions. [NNOPR §§ 602(A) and (B)(1)]

a. “Actual emissions” means the actual rate of emissions in tpy of any fee

pollutant emitted from a part 71 source over the preceding calendar year.

Actual emissions shall be calculated using each emissions unit’s actual

operating hours, production rates, in-place control equipment, and types of

materials processed, stored, or combusted during the preceding calendar

year. Actual emissions shall not include emissions of any one fee pollutant

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in excess of 4,000 TPY, or any emissions that come from insignificant

activities [NNOPR § 102(5)].

b. Actual emissions shall be computed using methods required by the permit

for determining compliance, such as monitoring or source testing data [40

CFR § 71.6(a)(7) and § 71.9(h)(3)].

c. If actual emissions cannot be determined using the compliance methods in

the permit, the permittee shall use other federally recognized procedures

[40 CFR § 71.6(a)(7) and § 71.9(e)(2)].

d. The term “fee pollutant” is defined in NNOPR § 102(24).

e. The term “regulated air pollutant” is defined in NNOPR § 102(50), except

that for purposes of this permit the term does not include any pollutant that

is regulated solely pursuant to 4 N.N.C. § 1121 nor does it include any

hazardous air pollutant designated by the Director pursuant to 4 N.N.C. §

1126(B).

f. The permittee should note that the applicable fee is revised each year to

account for inflation, and it is available from NNEPA starting on March 1

of each year.

g. The total annual fee due shall be the greater of the applicable minimum fee

and the sum of subtotal annual fees for all fee pollutants emitted from the

source. [NNOPR § 602(B)(2)]

5. The permittee shall retain, in accordance with the provisions of 40 CFR §

71.6(a)(3)(ii), all fee calculation worksheets and other emissions-related data used

to determine fee payment for 5 years following submittal of fee payment.

Emission-related data include emissions-related forms provided by NNEPA and

used by the permittee for fee calculation purposes, emissions-related spreadsheets,

and records of emissions monitoring data and related support information required

to be kept in accordance with 40 CFR § 71.6(a)(3)(ii) [40 CFR § 71.6(a)(7) and §

71.9(i)].

6. Failure of the permittee to pay fees in a timely manner shall subject the permittee

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

7. When notified by NNEPA of underpayment of fees, the permittee shall remit full

payment within 30 days of receipt of notification [40 CFR § 71.9(j)(2)].

8. A permittee who thinks an NNEPA assessed fee is in error and wishes to

challenge such fee, shall provide a written explanation of the alleged error to

NNEPA along with full payment of the NNEPA assessed fee. Within 90 days of

receipt of the correspondence, NNEPA shall review the data to determine whether

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the assessed fee was in error. If an error was made, the overpayment shall be

credited to the account of the permittee. [40 CFR § 71.9(j)(3)].

IV.B. Blanket Compliance Statement [CAA §§113(a) and 113(e)(1) and 40 CFR § 51.212(c),

§ 52.12(c), § 52.33, § 60.11(g), § 61.12(e), § 71.6(a)(6)(i) and (ii), and § 71.12]

1. The permittee must comply with all conditions of this Part 71 permit. Any permit

noncompliance, including, but not limited to, violation of any applicable

requirement; any permit term or condition; any fee or filing requirement; any duty

to allow or carry out inspection, entry, or monitoring activities; or any regulation

or order issued pursuant to 40 CFR Part 71 constitutes a violation of the Clean Air

Act and is grounds for enforcement action; permit termination, revocation and

reissuance, or modification; or denial of a permit renewal application. It shall not

be a defense for a permittee in an enforcement action that it would have been

necessary to halt or reduce the permitted activity in order to maintain compliance

with the conditions of this permit [CAA § 113(a); 40 CFR §§ 71.6(a)(6)(i) and

(ii), 71.12].

2. Determinations of deviations, continuous or intermittent compliance status, or

violations of this permit are not limited to the applicable testing or monitoring

methods required by the underlying regulations or this permit; other credible

evidence (including any evidence admissible under the Federal Rules of

Evidence) must be considered in such determinations. [CAA § 113(a) and

113(e)(1); 40 CFR § 51.212(c), § 52.12(c), § 52.33, § 60.11(g), and § 61.12(e)]

IV.C. Compliance Certifications [40 CFR § 71.6(c)(1), (5)] [NNOPR § 302(I)]

1. The permittee shall submit to NNEPA and US EPA Region 9 a semi-annual

certification of compliance with permit terms and conditions, including emission

limitations, standards, or work practices, postmarked by January 31 and July 31 of

each year and covering the previous six-month period ending on December 31

and June 30, respectively. The compliance certification shall be certified as to

truth, accuracy, and completeness by the permit-designated responsible official

consistent with Condition III.C.4 of this permit [40 CFR § 71.6(c)(1), (5)].

2. The certification shall include the following [40 CFR § 71.6(c)(5)(iii)]:

a. Identification of each permit term or condition that is the basis of the

certification.

b. Identification of the method(s) or other means used for determining the

compliance status of each term and condition during the certification

period, and whether such methods or other means provide continuous or

intermittent data.

c. The compliance status of each term and condition of the permit for the

period covered by the certification based on the method or means

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designated above. The certification shall identify each deviation and take

it into account in the compliance certification. The certification shall

identify as possible exceptions to compliance any periods during which

compliance is required but an excursion or exceedance has occurred

pursuant to this permit.

d. Whether compliance with each permit term was continuous or

intermittent.

e. If necessary, the permittee also shall identify any other material

information that must be included in the certification to comply with

Section 113(c)(2) of the Clean Air Act, which prohibits knowingly

making a false certification or omitting material information.

IV.D. Duty to Provide and Supplement Information [40 CFR § 71.6(a)(6)(v), 40 CFR §

71.5(b)]

The permittee shall furnish to NNEPA and US EPA Region 9, within a reasonable time,

any information that NNEPA and US EPA Region 9 may request in writing to determine

whether cause exists for modifying, revoking and reissuing, or terminating the permit, or

to determine compliance with the permit. Upon request, the permittee shall also furnish

to NNEPA and US EPA Region 9 copies of records that are required to be kept pursuant

to the terms of the permit, including information claimed to be confidential. Information

claimed to be confidential should be accompanied by a claim of confidentiality according

to the provisions of 40 CFR Part 2, Subpart B. The permittee, upon becoming aware that

any relevant facts were omitted or incorrect information was submitted in the permit

application, shall promptly submit such supplementary facts or corrected information.

The permittee shall also provide additional information as necessary to address any

requirements that become applicable to the facility after this permit is issued.

IV.E. Submissions [40 CFR § 71.5(d), § 71.6(a)(iii)(A) and (c)(1), and § 71.9(h)(2)]

Any document required to be submitted with this permit shall be certified by a

responsible official as to truth, accuracy, and completeness. Such certifications shall

state that based on information and belief formed after reasonable inquiry, the statements

and information in the document are true, accurate, and complete.

All documents required to be submitted, including reports, test data, monitoring data,

notifications, compliance certifications, fee calculation worksheets, and applications for

renewals and permit modifications shall be submitted to NNEPA and US EPA Region 9:

Navajo Nation Air Quality Control Program

Operating Permit Program

P.O. Box 529


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and

Director, Air Division (Attn: AIR-1)

EPA Region IX

75 Hawthorne Street


IV.F. Severability Clause [40 CFR § 71.6(a)(5)]

The provisions of this permit are severable, and in the event of any challenge to any

portion of this permit, or if any portion is held invalid, the remaining permit conditions

shall remain valid and in force.

IV.G. Permit Actions [40 CFR § 71.6(a)(6)(iii)]

This permit may be modified, revoked, reopened, and reissued, or terminated for cause.

The filing of a request by the permittee for a permit modification, revocation and

reissuance, or termination, or of a notification of planned changes or anticipated

noncompliance, does not stay any permit condition.

IV.H Administrative Permit Amendments [40 CFR § 71.7(d)] [NNOPR § 405(C)]

The permittee may implement the changes outlined in subparagraphs (1) through (5)

below immediately upon submittal of the request for the administrative revision. The

permittee may request the use of administrative permit amendment procedures for a

permit revision that:

1. Corrects typographical errors.

2. Identifies a change in the name, address, or phone number of any person

identified in the permit, or provides a similar minor administrative change at the

source.

3. Requires more frequent monitoring or reporting by the permittee.

4. Allows for a change in ownership or operational control of a source where the

NNEPA determines that no other change in the permit is necessary, provided that

a written agreement containing a specific date for transfer of permit

responsibility, coverage, and liability between the current and new permittee has

been submitted to the NNEPA;

5. Incorporates into the Part 71 permit the requirements from preconstruction review

permits authorized under an EPA-approved program, provided that such a

program meets procedural requirements substantially equivalent to the

requirements of 40 CFR §§ 71.7, 71.8 and 71.10 that would be applicable to the

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change if it were subject to review as a permit modification, and compliance

requirements substantially equivalent to those contained in 40 CFR § 71.6.

6. Incorporates any other type of change which NNEPA has determined to be similar

to those listed above in subparagraphs (1) through (5).

IV.I. Minor Permit Modifications [40 CFR § 71.7(e)(1)] [NNOPR § 405(D)]

1. The permittee may request the use of minor permit modification procedures only

for those modifications that:

a. Do not violate any applicable requirement.

b. Do not involve significant changes to existing monitoring, reporting, or

recordkeeping requirements in this permit.

c. Do not require or change a case-by-case determination of an emissions

limitation or other standard, or a source-specific determination for

temporary sources of ambient impacts, or a visibility or increment

analysis.

d. Do not seek to establish or change a permit term or condition for which

there is no corresponding underlying applicable requirement and that the

permittee has assumed to avoid an applicable requirement to which the

permittee would otherwise be subject. Such terms and conditions include:

(i) A federally enforceable emissions cap assumed to avoid

classification as a modification under any provision of Clean Air

Act Title I; and

(ii) An alternative emissions limit approved pursuant to regulations

promulgated under Section 112(i)(5) of the Clean Air Act.

e. Are not modifications under any provision of Title I of the Clean Air Act.

f. Are not required to be processed as a significant modification.

2. Notwithstanding the list of changes eligible for minor permit modification

procedures in paragraph (1) above, minor permit modification procedures may be

used for permit modifications involving the use of economic incentives,

marketable permits, emissions trading, and other similar approaches, to the extent

that such minor permit modification procedures are explicitly provided for in an

applicable implementation plan or in applicable requirements promulgated by

EPA.

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3. An application requesting the use of minor permit modification procedures shall

meet the requirements of 40 CFR § 71.5(c) and shall include the following:

a. A description of the change, the emissions resulting from the change, and

any new applicable requirements that will apply if the change occurs;

b. The permittee's suggested draft permit;

c. Certification by a responsible official, consistent with 40 CFR § 71.5(d),

that the proposed modification meets the criteria for use of minor permit

modification procedures and a request that such procedures be used; and

d. Completed forms for NNEPA and US EPA to use to notify affected States

as required under 40 CFR § 71.8.

e. If the requested permit revision would affect existing compliance plans or

schedules, related progress reports, or certification of compliance

requirements, and an outline of such effects.

4. The permittee may make the change proposed in its minor permit modification

application immediately after submittal of such application. After the permittee

makes the change allowed by the preceding sentence, and until NNEPA takes any

of the actions specified in NNOPR § 405(D)(6)(a) through (c), the permittee must

comply with both the applicable requirements governing the change and the

proposed permit terms and conditions. During this time period, the permittee need

not comply with the existing permit terms and conditions it seeks to modify.

However, if the permittee fails to comply with its proposed permit terms and

conditions during this period, the existing permit terms and conditions it seeks to

modify may be enforced against it.

5. The permit shield under 40 CFR § 71.6(f) may not extend to minor permit

modifications [40 CFR § 71.7(e)(1)(vi)].

IV.J. Group Processing of Minor Permit Modifications [40 CFR § 71.7(e)(2)]

1. Group processing of modifications by NNEPA may be used only for those permit

modifications:

a. That meet the criteria for minor permit modification procedures under

Condition IV.I.1 of this permit; and

b. That collectively are below the threshold level of 10 percent of the

emissions allowed by the permit for the emissions unit for which the

change is requested, 20 percent of the applicable definition of major

source in 40 CFR § 71.2, or 5 tons per year, whichever is least.

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2. An application requesting the use of group processing procedures shall meet the

requirements of 40 CFR § 71.5(c) and shall include the following:

a. A description of the change, the emissions resulting from the change, and

any new applicable requirements that will apply if the change occurs.

b. The permittee's suggested draft permit.

c. Certification by a responsible official, consistent with 40 CFR § 71.5(d),

that the proposed modification meets the criteria for use of group

processing procedures and a request that such procedures be used.

d. A list of the permittee's other pending applications awaiting group

processing, and a determination of whether the requested modification,

aggregated with these other applications, equals or exceeds the threshold

set under Condition IV.J.1.b above.

e. Certification that the permittee has notified US EPA of the proposed

modification. Such notification need only contain a brief description of

the requested modification.

f. Completed forms for NNEPA to use to notify affected States as required

under 40 CFR § 71.8 and US EPA as required under 40 CFR § 71.10(d).

3. The permittee may make the changes proposed in its minor permit modification

application immediately after it files such application. After the source makes the

changes allowed by the preceding sentence, and until NNEPA takes any of the

actions specified in NNOPR § 405(D)(6)(a) through (c), the permittee must

comply with both the applicable requirements governing the change and the

proposed permit terms and conditions. During this time period, the permittee need

not comply with the existing permit terms and conditions it seeks to modify.

However, if the permittee fails to comply with its proposed permit terms and

conditions during this time period, the existing permit terms and conditions it

seeks to modify may be enforced against it.

4. The permit shield under 40 CFR § 71.6(f) may not extend to group processing of

minor permit modifications [40 CFR § 71.7(e)(2)(vi)].

IV.K. Significant Permit Modifications [40 CFR § 71.7(e)(3)] [NNOPR § 405(E)]

1. The permittee must request the use of significant permit modification procedures

for those modifications that:

a. Do not qualify as minor permit modifications or as administrative

amendments.

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b. Are significant changes in existing monitoring permit terms or conditions.

c. Are relaxations of reporting or recordkeeping permit terms or conditions.

2. Nothing herein shall be construed to preclude the permittee from making changes

consistent with Part 71 that would render existing permit compliance terms and

conditions irrelevant.

3. The permittee must meet all requirements of Part 71 for applications for

significant permit modifications. For the application to be determined complete,

the permittee must supply all information that is required by 40 CFR § 71.5(c) for

permit issuance and renewal, but only that information that is related to the

proposed change [40 CFR §§ 71.7(e)(3)(ii) and 71.5(a)(2)].

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

NNEPA shall reopen and revise the permit prior to expiration under any of the following

circumstances:

1. Additional applicable requirements under the Clean Air Act become applicable to

a major Part 71 source with a remaining permit term of 3 or more years.

2. Additional requirements (including excess emissions requirements) become

applicable to an affected source under the acid rain program. Upon approval by

the Administrator, excess emissions offset plans shall be deemed to be

incorporated into the permit.

3. NNEPA or US EPA determines that the permit contains a material mistake or that

inaccurate statements were made in establishing the emissions standards or other

terms or conditions of the permit.

4. NNEPA or US EPA determines that the permit must be revised or revoked to

assure compliance with the applicable requirements.

IV.M. Property Rights [40 CFR § 71.6(a)(6)(iv)]

This permit does not convey any property rights of any sort, or any exclusive privilege.

IV.N. Inspection and Entry [40 CFR § 71.6(c)(2)]

Upon presentation of credentials and other documents as may be required by law, the

permittee shall allow authorized representatives from NNEPA and US EPA to perform

the following:

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1. Enter upon the permittee’s premises where a Part 71 source is located or

emissions-related activity is conducted, or where records must be kept under the

conditions of this permit;

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

the conditions of this permit;

3. Inspect at reasonable times any facilities, equipment (including monitoring and air

pollution control equipment), practices, or operations regulated or required under

the permit; and

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

substances or parameters for the purpose of assuring compliance with the permit

or applicable requirements.

IV.O. Emergency Provisions [40 CFR § 71.6(g)]

1. In addition to any emergency or upset provision contained in any applicable

requirement, the permittee may seek to establish that noncompliance with a

technology-based emission limitation under this permit was due to an emergency.

To do so, the permittee shall demonstrate the affirmative defense of emergency

through properly signed, contemporaneous operating logs, or other relevant

evidence that:

a. an emergency occurred and that the permittee can identify the cause(s) of

the emergency;

b. the permitted facility was at the time being properly operated;

c. during the period of the emergency the permittee took all reasonable steps

to minimize levels of emissions that exceeded the emissions standards, or

other requirements in this permit; and

d. the permittee submitted notice of the emergency to NNEPA within 2

working days of the time when emissions limitations were exceeded due

to the emergency. This notice must contain a description of the

emergency, any steps taken to mitigate emissions, and corrective actions

taken. This notice fulfills the requirements of Condition III.C.2 of this

permit.

e. In any enforcement preceding the permittee attempting to establish the

occurrence of an emergency has the burden of proof.

2. An "emergency" means any situation arising from sudden and reasonably

unforeseeable events beyond the control of the permittee, including acts of God,

which situation requires immediate corrective action to restore normal operation,

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and that causes the source to exceed a technology-based emissions limitation

under this permit due to unavoidable increases in emissions attributable to the

emergency. An emergency shall not include noncompliance to the extent caused

by improperly designed equipment, lack of preventive maintenance, careless or

improper operation, or operator error.

IV.P. Transfer of Ownership or Operation [40 CFR § 71.7(d)(1)(iv)]

A change in ownership or operational control of this facility may be treated as an

administrative permit amendment if the NNEPA determines no other change in this

permit is necessary and provided that a written agreement containing a specific date for

transfer of permit responsibility, coverage, and liability between the current and new

permittee has been submitted to NNEPA.

IV.Q. Off Permit Changes [40 CFR § 71.6(a)(12)] [NNOPR § 404(B)]

The permittee is allowed to make certain changes without a permit revision, provided that

the following requirements are met:

1. Each change is not addressed or prohibited by this permit;

2. Each change must comply with all applicable requirements and may not violate

any existing permit term or condition;

3. Changes under this provision may not include changes or activities subject to any

requirement under 40 CFR Parts 72 through 78 or that are modifications under

any provision of Title I of the Clean Air Act;

4. The permittee must provide contemporaneous written notice to NNEPA and US

EPA Region 9 of each change, except for changes that qualify as insignificant

activities under 40 CFR § 71.5(c)(11). The written notice must describe each

change, the date of the change, any change in emissions, pollutants emitted and

any applicable requirements that would apply as a result of the change;

5. The permit shield does not apply to changes made under this provision; and

6. The permittee must keep a record describing all changes that result in emissions

of any regulated air pollutant subject to any applicable requirement not otherwise

regulated under this permit, and the emissions resulting from those changes.

IV.R. Permit Expiration and Renewal [40 CFR §§ 71.5(a)(1)(iii), 71.6(a)(11), and 71.7(b) and

(c)]

1. This permit shall expire upon the earlier occurrence of the following events:

a. five (5) years elapses from the date of issuance; or

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b. the source is issued a Part 70 permit by NNEPA, provided that EPA has

granted the Navajo Nation treatment as a state and primacy for a Part 70

program and that NNEPA issues the permit consistent with the VCA.

2. Expiration of this permit terminates the permittee’s right to operate unless a

timely and complete permit renewal application has been submitted on or before a

date 6 months, but not more than 18 months, prior to the date of expiration of this

permit.

3. If the permittee submits a timely and complete permit application for renewal that

is consistent with 40 CFR § 71.5(a)(2), but NNEPA has failed to issue or deny the

renewal permit, then the permit shall not expire until the renewal permit has been

issued or denied and any permit shield granted pursuant to 40 CFR § 71.6(f) may

extend beyond the original permit term until renewal.

4. The permittee’s failure to have a Part 71 permit is not a violation of 40 CFR Part

71 until NNEPA takes final action on the permit renewal application. This

protection shall cease to apply if, subsequent to the completeness determination,

the permittee fails to submit any additional information identified as being needed

to process the application by the deadline specified in writing by NNEPA.

5. Renewal of this permit is subject to the same procedural requirements that apply

to initial permit issuance, including those for public participation and affected

State and tribal review.

6. The application for renewal shall include the current permit number, description

of permit revisions and off-permit changes that occurred during the permit term,

any applicable requirements that were promulgated and not incorporated into the

permit during the permit term, and other information required by the application

form.

IV.S. Additional Permit Conditions [Voluntary Compliance Agreement, Article 6]

This permit is issued pursuant to the Voluntary Compliance Agreement between the

permittee and the Navajo Nation. The permittee shall comply with the terms of this

permit and shall be subject to enforcement of the permit by the Navajo Nation EPA,

pursuant to the terms of the Voluntary Compliance Agreement. The permittee’s

agreement to comply is effective upon the permittee’s written acceptance of the permit

and expires at the end of the permit term, unless the permit is renewed. The permittee’s

agreement to comply may be withdrawn during the permit term only if the Voluntary

Compliance Agreement is terminated or expires as provided in that Agreement.

IV.T. Part 71 Permit Enforcement [Voluntary Compliance Agreement, Section 5.4.5; 40 CFR

§ 71.12]

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1. The Navajo Nation has the authority to:

a. Develop compliance plans and schedules of compliance;

b. Conduct compliance and monitoring activities, including review of

monitoring reports and compliance certifications, inspections, audits,

conducting and/or reviewing stack tests, and issuing requests for

information either before or after a violation is identified; and

c. Conduct enforcement-related activities, including issuance of notices,

findings, and letters of violation, and development of cases up to, but not

including, the filing of a complaint or order.

2. Violations of any applicable requirement; any permit term or condition; any fee or

filing requirement; any duty to allow or carry out inspection, entry, or monitoring

activities; or any regulation or order issued pursuant to 40 CFR Part 71 are

violations of the Clean Air Act and are subject to full Federal enforcement

authorities available under the Clean Air Act.

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Attachment A

Dust Control Plan

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Attachment B

Phase II Acid Rain Permit Renewal

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Attachment C

NESHAP for Coal- and Oil-Fired Electric Utility

Steam Generating Units,

40 CFR Part 63, Subpart UUUUU –

Compliance, Monitoring, Testing, Notification,

Recordkeeping, and Reporting Requirements

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

Post Office Box 529, Fort Defiance, AZ 86504 Bldg. #2837 Route 112 Telephone (928) 729-4096, Fax (928) 729-4313, Email [email protected]

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


Permit No. NN-OP-15-06

1. Facility Information

a. Permittee


5 Miles East of Page, off U.S. Highway 98

Page, Arizona 86040

Mailing Address:

P.O. Box 850

Page, Arizona 86040

Managing Participant Name: Salt River Project Agricultural Improvement

and Power District (SRP)*

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

Phoenix, Arizona 85072-2025

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

participant in this permit since it acts as the facility operator, and has accepted the

responsibility to obtain environmental permits for Navajo Generating Station, including

an Acid Rain permit and Part 71 Permit. In addition to SRP (21.7%), the other 5 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%)

THE NAVAJO NATION RUSSELL BEGAYE PRES I DE NT

JONATHAN NEZ VICE PRESIDENT


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5. Tucson Electric Power (TEP) (7.5%)

b. Contact Information

Facility Contact: Paul Ostapuk Phone: (928) 645-6577

O&M Manager Facsimile: (928) 645-7298

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

Plant Manager Facsimile: (928) 645-7298

c. Description_of_Operations,_Products

The facility is a 2,250 net Megawatt coal-fired power plant. Bituminous coal is mined by

Peabody Energy at the Kayenta Mine complex and delivered by electric rail to NGS.

Coal is then transferred via enclosed conveyor systems to the boilers or to a storage pile

for later use.

The management of coal combustion residues and the delivery of limestone for the SO2

scrubbers is contracted to a third party entity but SRP remains the responsible party for

truck loading and unloading operations, material transfer, storage, and disposal activities.

Coal combustion residues include fly ash, bottom ash, and scrubber byproducts. Bottom

ash and scrubber byproducts are handled in a wet state which minimizes the potential for

dust emissions.

d. History

The facility consists of three (3) coal-fired utility boilers and two oil-fired auxiliary

boilers. The permittee receives the coal, which has an average sulfur content between

0.5% and 0.75% by weight, from a nearby coal mine. Coal-fired boilers U1, U2, and

U3 and oil-fired auxiliary boilers AUX-A and AUX-B commenced construction in

1970. The construction of these boilers predated EPA's preconstruction permit

regulations.

Particulate emissions from boilers U1 through U3 are controlled by Electrostatic

Precipitators (ESP). Flue Gas Desulfurization (FGD) systems for SO2 control were

installed in 1997, 1998, and 1999 on boilers U3, U2, and U1, respectively. The

associated limestone handling system was constructed in 1997. In 2008, the source

received a PSD permit to install Low-NOX burners (LNBs) and Separated Over-fire Air

(SOFA) systems on the three existing boilers. The LNB/SOFA systems were installed

in 2009, 2010, and 2011 on boilers U3, U2, and U1, respectively. The permittee also

plan to install mercury control systems in 2015 for boilers U1 through U1 through U3

using powdered activated carbon (PAC) and calcium bromide.

On February 9, 2015, the permittee submitted a minor NSR permit application to both

US EPA and NNEPA for the construction of a refined coal system as part of the coal

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handling operation at the facility. The refined coal system will be owned and operated

by a third-party which will be contracted out by SRP. This NSR permit application is

currently reviewed by US EPA.

e. Existing Approvals

The source has been operating under Part 71 Operating Permit NN-ROP-05-06, issued

on July 3, 2008, and the following approvals:

(a) PSD Permit #AZ 08-01, issued on November 20, 2008.

(b) Title V Permit Reopening #NN-ROP-05-06-A, issued on October 28, 2011.

(c) PSD Permit Amendment #AZ 08-01A, issued on February 6, 2012; amended on

August 26, 2015.

(d) Tribal Minor NSR Permit #T-0004-NN, issued on August 26, 2015

f. Proposed Modifications to the Part 71 Permit:

The permittee requested the following changes made to their Part 71 permit:

(1) Changes to the maximum heat input capacity of the boilers:

The maximum heat input capacity for each of the boilers U1, U2, and U3 has

been reduced from 7,725 MMBtu/hr to 7,410 MMBtu/hr. This change was

requested by the permittee because the heating value of coal received at this

plant has decreased in recent years and the revised heat input of 7,410

MMBtu/hr for each boiler better reflects the estimated maximum boiler

capacity. This change will not result in increases of emissions from these units

and is considered a minor permit modification.

(2) Revise the insignificant activities listed:

The list of insignificant activities and emissions in Section 1.j of this Statement

of Basis has been updated based on information submitted by the permittee on

July 24, 2014. The new emergency fire pump (NGS-120A) is subject to the

New Source Performance Standards (NSPS) for Stationary Compression

Ignition Internal Combustion Engines (40 CFR Part 60, Subpart IIII) and the

applicable requirements of this NSPS will be included in this Part 71 permit.

These changes are considered a significant permit modification.

(3) Update the unit description for coal hopper feeders (L1-L12):

The permittee installed a wet dust suppression system (Mee Fog System) to

control the twelve (12) coal hopper feeders (L1-L12) in 2007. This information

was not include in the permit application for the previous Part 71 permit, issued

on January 4, 2008. However, the installation of this control equipment

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decreases the particulate emissions from these units and is considered a minor

permit modification.

(4) Add operating limits for auxiliary boilers AUX A and AUX B:

In order to be qualify for “limited-use” units under 40 CFR Part 63, Subpart

DDDDD (National Emission Standards for Hazardous Air Pollutants for

Industrial, Commercial, and Institutional Boilers and Process Heaters), the

permittee requested to include an operating limit of 10% of the annual capacity

into this Part 71 renewal permit for the auxiliary boilers. This Part 71 permit

will also include additional recordkeeping requirements for these auxiliary

boilers. These proposed changes are considered significant permit

modifications.

(5) Installation of PM CEMS with Boilers U1, U2, U3:

In an addendum to Title V renewal application received on January 21, 2015,

the permittee stated that they plan to comply with the new PM emission limit in

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

Electric Utility Steam Generating Units (NESHAP, Subpart UUUUU) using PM

Continuous Emission Monitoring Systems (CEMS). The PM CEMS have been

installed for each of the boilers U1, U2, U3. Since the PM emission limit in this

NESHAP, Subpart UUUUU is most stringent applicable PM emission limit for

boilers U1, U2, and U3, operating PM CEMS according to the NESHAP

requirements exempts the permittee from Continuous Assurance Monitoring

(CAM) requirements (40 CFR Part 64) and the existing CAM requirements for

boilers U1, U2, and U3 in the Part 71 permit could be removed. However, in an

addendum to Title V renewal application received on March 31, 2015, the

permittee stated that PM CEMS are still not operating properly and requested

the existing CAM requirements stayed in the Part 71 renewal permit until such

time the PM CEMS are fully in operation. Incorporating the PM CEM

requirements to the Part 71 permit is considered a significant permit

modification.

The procedure for reviewing this Part 71 renewal permit fulfills the minor permit

modification requirements specified in 40 CFR § 71.7(e)(1) and NNOPR § 405(D), and

the significant permit modification requirements specified in 40 CFR § 71.7(e)(3) and

NNOPR § 405(E).

g. Permitted Emission Units and Control Equipment

Unit ID/


Maximum

Capacity

Commenced

Construction

Date

Control Method

U1/

Stack S1




and a COMS.

7,410 MBtu/hr;

750 Net MW 1970

ESP1; FGD system

SCBR1 (1999);

LNB/SOFA*(2011);


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Unit ID/


Maximum

Capacity

Commenced

Construction

Date

Control Method

U2/

Stack S2




and a COMS.

7,410 MBtu/hr;

750 Net MW 1970

ESP2; FGD system

SCBR2 (1998);

LNB/SOFA*(2010);


\U3/

Stack S3




and a COMS.

7,410 MBtu/hr;

750 Net MW 1970

ESP3; FGD system

SCBR3 (1997);

LNB/SOFA*(2009);


AUX A One (1) auxiliary boiler;


AUX B One (1) auxiliary boiler;


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


BC-1 through

BC-4 Four (4) conveyors to the yard surge bin

1,800 tons/hr

(each) 1970 DC-8

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

BFD-5A,

BC-5 Two (2) reclaim conveyors

1,800 tons/hr

(each) 1970 DC-8

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

BC-6A through

BC-6C Three (3) conveyors to the stacker/reclaimer

1,800 tons/hr

(each) 1970

wet suppression/

enclosure

BC-7 One (1) conveyor to the emergency reclaim

hopper 1,500 tons/hr 1970 wet suppression

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

BC-8A,

BC-8B Two (2) conveyors to plant surge bin

1,500 tons/hr

(each) 1970 DC-8

BC-8AS,

BC-8BS Two (2) screens

1,500 tons/hr

(each) 1970 DC-8

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

BC-9A,

BC-9B

Two (2) conveyors to the coal silos for boilers

U1 and U2

1,500 tons/hr

(each) 1970 DC-5

BC-10A,

BC-10B

Two (2) conveyors to the coal silos for boiler

U3

1,500 tons/hr

(each) 1970 DC-5

CC-1A through

CC-9A; CC-1B

through CC-9B

Three (3) enclosed cascading conveying systems

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

U3

1,500 tons/hr

(each) 1970

DC-1 through DC-4,

DC-6, and DC-7

Silos 1A through


3,000 tons/hr

(each) 1970

DC-1, DC-2, and

baghouse PR-1.

Silos 2A through


3,000 tons/hr

(each) 1970

DC-3, DC-4, and

baghouse PR-2.

Silos 3A through


3,000 tons/hr

(each) 1970

DC-6, DC-7, and

baghouse PR-3.

CS Outdoor coal storage piles 3,300 tons/hr


Limestone Handling System Associated with the FGD Systems

Unloading Bay

A and B Two (2) truck unloading operations

38 tons/hr

(each) 1997 N/A

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

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Unit ID/


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


Fly Ash Handling System

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

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

Silo 1 and 2

Loading

Two (2) partially enclosed fly ash truck loading

operations

38 tons/hr

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

DWB-A through

DWB-F

Six (6) bottom ash truck loading operations.

The bottom ash is processed in a wet form

46 tons/hr

(each) 1970 wet suppression

Soda Ash/Lime Handling Systems

SAB-1A, SAB-

2A, SAB-1B,

SAB-2B

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


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


Reagent Handing Systems

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

PAC Silo B PAC storage silo 40 tons 2015 integral baghouse

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

Fugitive-CaBr2 Truck traffic on unpaved roads for Calcium

Bromide delivery 365 VMT/yr** 2015 water spray

Miscellaneous Operations

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

(total) 1970 N/A

TR Fugitive emissions from unpaved roads N/A 1970 wet suppression Note: (*) LNB/SOFA = Low-NOX burner (LNB) and Separated Overfire Air (SOFA) system.

(**) VMT = vehicle miles traveled.

h. Unpermitted Emission Units and Control Equipment

No unpermitted emission units were found to be operating at this source during this

review process.

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i. New Emission Units and Control Equipment

There is no new emission unit or control equipment proposed during this review process.

j. Insignificant Activities and Emissions

This stationary source also emits air pollutants from insignificant activities and at

insignificant emissions levels, defined in 40 CFR § 71.5(c)(11)(ii) as emissions from an

emissions unit with the potential to emit non-hazardous regulated air pollutants in an

amount less than 2 tons per year or a single HAP in an amount less than 1,000 pounds

per year or the de minimis level established under CAA § 112(g), whichever is less.

These emissions come from the following insignificant activities and emissions units:

(a) Nine (9) diesel-fired emergency generators, as specified in Table 1 below:

Table 1 – Diesel-Fired Emergency Generators

Unit ID Unit Description Installation

Date Max. Power

Output (hp)

Type of

Engine* (CI or SI)

EG1 Emergency generator for boilers U1

and U2 1983 515 CI

EG2 Emergency generator for boiler U3 1976 280 CI

EG3 Warehouse emergency generator Before

4/1/2006 70 CI

NPG-746 Emergency generator 2003 469 CI NGS-120A Emergency fire pump 2010 300 CI NPG-529 Portable generator 1987 335 CI NPG-384 Portable generator 1977 141 CI NPG-811 Portable generator 2007 34 CI NPG-818 Portable generator 2007 717 CI

*Note: CI = Compression Ignition; SI = Spark Ignition

(b) Equipment used during facility-wide welding activities, identified as WL.

(c) Equipment used during abrasive blasting operations.

(d) Fuel and oil storage tanks as described in Table 2 below:

Table 2 - Fuel and Oil Storage Tanks

Unit ID Type of Liquid

Stored

Construction

Date

Max. Capacity

(gallons)

NGS-062A Diesel 1991 14,000

NGS-063A Diesel 1991 14,000

NGS-064A Gas 1991 12,000

NGS-065A Used Oil 1991 2,500

NGS-067A Used Oil 1991 550

NGS-068A 30 Wt Engine Oil 1991 550


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Stored

Construction

Date

Max. Capacity

(gallons)


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-079A Mobile Diesel Early '70s 200






NGS-085A Mobile Diesel 1974 400



NGS-090A Turbine Lube Oil 1974 7,450

NGS-091A Turbine Lube Oil 1974 650








NGS-099A H2 Seal Oil 1975 650



NGS-102A Transformer Oil 1973 5,600



NGS-106A Diesel 1974 10,000

NGS-107A Lube Oil 1991 750

NGS-108A Diesel 1991 900





NGS-113A Used Diesel 2012 500

NGS-113B Used Diesel 2012 500

NGS-113C Used Diesel 2012 500


NGS-115A Diesel Unknown 200



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Stored

Construction

Date

Max. Capacity

(gallons)




NGS-121A Lube Oil N/A 550



NGS-124A Diesel N/A 100


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-131 Used Oil for Heating N/A 550

NGS-131A

through 131O Used Oil 1991 540 (each)



NGS-134A

through 134D Used Oil N/A 250 (each)

NGS-135 Used Oil N/A 100

(e) Landscaping, building maintenance, or janitorial activities.

(f) Hand-held or manually operated equipment used for buffing, polishing,

carving, cutting, drilling, machining, routing, sanding, sawing, surface

grinding, or tuning of precision parts, metals, plastics, masonry, glass, or

wood.

(g) Equipment used during powder coating operations.

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

(i) Equipment used during maintenance painting and surface coating.

(j) Equipment used during parts cleaning.

(k) Equipment used during maintenance sand blasting.

(l) Other emissions units with the potential to emit insignificant levels of

regulated air pollutants or HAPs, as described in Table 3 below:

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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/rectifier set 165 80




Transformer 4,160 V (lake pump) 1,259 3

Transformer 480 V (lake pump) 160 2

Waste oil storage tank (cent yard) 500 1

Generator, diesel (Generac) 265 1

Recycle slurry system gear box 16 12

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Unit Description Max. Capacity

(gallons) Number of Units

Recycle slurry system gear box 22 12

Oxidation air system oil res. 60 9

Recycle valve Hydraulic sys. 120 3

Reactivator agitator 13 30

Limestone feed tank agitator 24 3

Absorber sump agitator 0.75 6

Ball mill gear box 52 2

Ball mill lube reservoir tank 110 2

Limestone conveyor gear box 39 3

Limestone transfer tank agitator 44 1

Filtrate raw water tank gear box 44 1

Ball mill sump tank agitator 7 2

LSP sump agitator 0.75 3

Filtrate transfer tank agitator 24 1

Secondary vacuum pump gear box 4.5 3

Absorber holding tank agitator 23 10

Bi-product sump agitator 1.5 2

Primary dewatering agitator 2 6

Conveyer feedbelt gear box 1.5 2

Antifreeze storage tank (NGS-069A) 550 1

Waste antifreeze storage tank (NGS-066A) 1,000 1

Sulfuric acid tank (NGS-201) 20,000 1

Sulfuric acid tank (NGS-202, 203, and 204) 15,000 3

Sulfuric acid tank (NGS-205) 10,000 1

Ammonia tank (NGS-208) 10,000 1

Ferric chloride tank (NGS-209) 16,000 1

Acid or caustic tank (NGS-210 and 211) 24,000 2

Sodium hydroxide tank (NGS-206 and 207) 10,000 2

Sodium hypochlorite tank (NGS-212, 213, and

214) 4,500 3

Scale inhibiter tank (NGS-215 through 220) 2,000 6

Dust Suppressant (Dusbloc) Tank 1,000 1

Dust Suppressant (Dusbloc) Tank 4,000 1

k. Enforcement Issue

There are no enforcement actions pending.

l. Emission Calculations

See Appendix A of this document for detailed calculations (pages 1 through 16).

m. Potential to Emit

Potential to emit (PTE) means the maximum capacity to emit any CAA-regulated air

pollutant under the facility’s physical and operational design. Any physical or

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operational limitation on the maximum capacity of this facility to emit an air pollutant,

including air pollution control equipment and restrictions on hours of operation or on

the type or amount of material combusted, stored, or processed, may be treated as a part

of its design if the limitation is enforceable by US EPA or NNEPA. Actual emissions

are typically lower than PTE.

Potential to Emit

(tons/year)

Process/facility PM PM10 PM2.5 SO2 NOx VOC CO HAPs

Boiler U1 1,947 1,097 488 3,246 7,789 75.3 4,868 22.7

Boiler U2 1,947 1,097 488 3,246 7,789 75.3 4,868 22.7

Boiler U3 1,947 1,097 488 3,246 7,789 75.3 4,868 22.7

Auxiliary

Boilers 3.92 1.96 0.49 13.9 47.1 0.39 9.81 1.19

Coal Handling 5.91 3.41 2.51 - - - - -

Coal Piles

(Fugitive) 5.43 2.57 0.39 - - - - -

Limestone

Handling 4.61 2.98 2.98 - - - - -

Limestone Piles

(Fugitive) 4.60 2.17 0.33 - - - - -

Fly Ash

Handling 29.2 29.2 29.2 - - - - 0.01

Soda Ash/Lime

Handling 0.26 0.26 0.26 - - - - -

Cooling Towers 19.2 19.2 19.2 - - - - -

PAC Storage

Silos 0.90 0.90 0.90 - - - - -

Unpaved Roads

associated with

PAC and CaBr2

Delivery

1.28 0.33 0.03 - - - - -

Unpaved Roads

(Fugitive) 546 141 14.1 - - - - -

Emergency

Generators

(Insignificant)

1.57 1.57 1.57 1.47 22.2 1.77 4.78 Negligible

Other

Insignificant

Activities*

15.3 15.3 15.3 - - Less than

5.00 - Negligible

PTE of the

Entire Source 6,481 3,513 1,550 9,752 23,437 233 14,620 69.3

Title V Major

Source

Thresholds

NA 100 100 100 100 100 100

10 for a

single HAP

and 25 for

total HAPs

*Note: This is an estimate on the PM/PM10/PM2.5 emissions from the welding and blasting operations, and VOC/HAP emissions

from the parts cleaning, surface coating operations, and the storage tanks.

(a) The potential to emit of PM10, PM2.5, SO2, VOC, CO and NOx are equal to or

greater than 100 tons per year. In addition, the potential to emit of HAPs from

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this source is greater than 10 tons per year of a single HAP and greater than 25

tons per year of total HAPs. Therefore, this source is considered a major source

under 40 CFR § 71.2 (defining “major source” for purposes of the Federal

Operating Permit Program).

(b) This source is located in an attainment area and is in one of the 28 source

categories listed in 40 CFR § 52.21(b)(1)(i)(a). The potential to emit PM and

all relevant criteria pollutants of this source is greater than 100 tons per year.

Therefore, this source is an existing major source under the Prevention of

Significant Deterioration (PSD) program.

n. Actual Emissions

The following table shows the actual emissions from the source. This information

reflects the 2012 emission inventory data submitted by the permittee to NNEPA and

the greenhouse gas (GHG) information reported to U.S. EPA under the GHG

reporting program (40 CFR Part 98).

Pollutant Actual Emissions (tons/year)

PM10 432

SO2 4,404

VOC 200

NOx 16,276

Hydrogen Chloride 6.0

Hydrogen Fluoride 9.0

Greenhouse Gas (GHG) 17,022,237

2. Tribe Information

a. General

The Navajo Nation has the largest land base of any tribe in the country, covering more

than 27,000 square miles in three states: Arizona, Utah, and New Mexico. The Navajo

Nation currently is home to more than 260,000 people. Industries on the Navajo Nation

include oil and natural gas production, coal and uranium mining, electric generation and

distribution, and tourism.

b. Local air quality and attainment status

All areas of the Navajo Nation are currently designated as attainment or unclassifiable

for all pollutants for which a National Ambient Air Quality Standard (NAAQS) has

been established.

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3. Prevention of Significant Deterioration (PSD) Applicability

This source is in one of the 28 source categories listed in 40 CFR § 52.21(b)(1)(i)(a) and has

potential to emit PM and all relevant criteria pollutants greater than 100 tons per year.

Therefore, this source is considered an existing PSD major source. This source commenced

construction in 1970 and commenced modifications in 1997 (installation of the FGD

systems) and 2008 (installation of LBN/SOFA systems). The construction of this source

predated the PSD applicability date of June 1, 1975. Therefore, this source was not required

to obtain a preconstruction permit when it was constructed in 1970. The modifications in

1997 (installation of the FGD systems) did not result in an emissions increase above the PSD

significance thresholds in 40 CFR § 52.21. Therefore, the modification that commenced in

1997 did not trigger PSD.

A PSD permit was issued to this source on July 3, 2008 for the installation of LNB/SOFA

systems for the existing three boilers U1 through U3. An amendment to this PSD permit was

issued on February 8, 2012. According to the requirements in the amended PSD permit, the

permittee is required to comply with the following emission limits for each of the boilers U1

through U3:

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

(1) 0.23 lb/MMBtu based on a 30-day rolling average, and

(2) 0.15 lb/MMBtu based on a 12-month rolling average.

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

In addition, the permittee is required to install CO CEMS (Continuous Emissions Monitoring

System) to demonstrate compliance with the CO emission limits specified in the PSD

permits.

The above emission limits and the associated compliance monitoring, recordkeeping, and

reporting requirements have been included in this Part 71 permit renewal.

4. Federal Rule Applicability

(a) This source is subject to the source-specific Federal Implementation Plan (FIP) for

Navajo Generating Station, Navajo Nation (40 CFR § 49.5513) which was

promulgated on March 5, 2010 and later amended on August 8, 2014 to incorporate

the Regional Haze Best Available Retrofit Technology (BART) requirements.

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

emission limits on a plant-wide basis:

(1) The SO2 emissions shall not exceed 1.0 lb/MMBtu averaged over any three-

hour period;

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(2) The PM emissions shall not exceed 0.06 lb/MMBtu as averaged from at least

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

and collecting a minimum sample of 30 dry standard cubic feet;

For the stacks of Units U1, U2, and U3, opacity shall not exceed 20% averaged over a

6 minute period, excluding condensed water droplets, or 40% averaged over 6 minutes

during absorber upset transition periods, pursuant to 40 CFR § 49.5513(d)(4).

For dust emissions associated with coal transfer and storage and other dust-generating

activities, opacity shall not exceed 20%, as determined using 40 CFR Part 60,

Appendix A-4, Method 9. The permittee is required to operate and maintain the

existing dust suppression methods for controlling dust from the coal handling and

storage facilities. A dust control plan was submitted by the permittee on June 4, 2010

and a revised plan was received on February 2, 2015. The revised dust control plan is

included in this Part 71 permit renewal as Attachment A.

The permittee shall also comply with the testing, monitoring, reporting, and

recordkeeping requirements specified in 40 CFR § 49.5513(e) and (f).

This FIP was amended on August 8, 2014 to include BART requirements (effective

October 7, 2014). Pursuant to 40 CFR § 49.5513(j)(3), total cumulative NOX

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

not exceed the 2009-2044 NOX Cap (494,899 tons). Compliance with this NOx

emission limit must be demonstrated by the operation of the existing NOX CEMS.

The applicable operating, maintenance, recordkeeping, and reporting requirements

for the NOx CEMS specified in the FIP have been incorporated into this Part 71

permit.

This FIP also requires the source to select and implement one of four operating

scenarios listed under 40 CFR § 49.5513(j)(3)(i) to ensure compliance with the NOX

emission cap limit. However, pursuant to 40 CFR § 49.5513(j)(4)(i), the permittee

has until December 1, 2019 to notify U.S. EPA of its choice of operating scenario.

Therefore, the requirements associated with these four operating scenarios are not

included in this Part 71 permit. Pursuant to 40 CFR § 49.5513(j)(4)(iii), the source is

required to submit a permit revision application no later than December 31, 2020 to

incorporate the specific requirements, including compliance monitoring,

recordkeeping, and reporting requirements, associated with the selected operating

scenario.

(b) The existing boilers U1 through U3 are considered utility units under the definition of

40 CFR § 72.2. Therefore, these boilers are subject to the Acid Rain Program

requirements (40 CFR Part 72 through 40 CFR Part 78), pursuant to 40 CFR §

72.6(a)(3). An Acid Rain Renewal Application was received on June 19, 2013 and the

renewal of the acid rain permit will be issued with this Part 71 permit renewal.

Pursuant to 40 CFR § 72.9, the permittee shall comply with the following:

of 29

(1) The SO2 and NOX continuous emission monitoring requirements in 40 CFR

Part 75.

(2) Acid rain emissions limitations for sulfur dioxide in 40 CFR Part 73. Pursuant

to 40 CFR § 73.10(b) and the allowance allocations provided on October 30,

2000, the phase II SO2 allowance allocations for the boilers at this source are

listed in the table below:

Emission

Unit

SO2 Allowance for years

2010 and beyond (tons/yr)

Boiler U1 24,949

Boiler U2 23,354

Boiler U3 23,693

Facility Total 71,996

Beginning in 2007, the SO2 allowance allocations apply to the entire facility,

instead of each individual emission unit at this facility.

(3) Acid rain emissions limitations for nitrogen oxides in 40 CFR Part 76 for 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) includes the following specific

requirements for the three (3) coal-fired boilers at Navajo Generating Station: (1)

Pursuant to 40 CFR § 52.145(d)(2), the SO2 emissions from each of the coal fired

boilers (boilers U1, U2, and U3) shall not exceed 42 ng/J (0.1 lbs/MMBtu) heat input;

and (2) Pursuant to 40 CFR § 52.145(d)(3), compliance with the emission limit shall

be determined daily on a plant-wide rolling annual basis.

(d) This source is subject to the Regional Haze Rule (40 CFR § 51.308) because it is a

BART-eligible source (that is, a fossil-fuel fired steam electric plant of more than 250

MMBtu/hr heat input which was not in operation prior to August 7, 1962, was in

existence on August 7, 1977, and has the potential to emit greater than 250 tons per

year of any air pollutant, see 40 CFR § 51.301) that may reasonably be anticipated to

cause or contribute to any impairment of visibility in a mandatory Class I area.

Pursuant to 40 CFR § 51.308(e), States are required to submit implementation plans

that, among other measures, contain either emission limits representing Best Available

Retrofit Technology (BART) for BART-eligible sources that may reasonably be

anticipated to cause or contribute to any impairment of visibility in any mandatory

Class I area, or alternative measures that provide for greater reasonable progress than

BART. Under the Clean Air Act, 42 USC § 7601(d), and the Tribal Authority Rule, 40

CFR § 49.11(a), EPA may promulgate a federal implementation plan in the absence of

a tribal implementation plan. Under this authority, EPA promulgated a source-specific

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FIP containing BART requirements for this source; the FIP is codified at 40 CFR §

49.5513(j).

(e) The Clean Air Mercury Rule (CAMR, CAA § 112(n)) was promulgated on May 18,

2005 and was developed to permanently cap and reduce the mercury (Hg) emissions

from coal-fired power plants. However, on February 8, 2008, the U.S. Court of

Appeals for the District of Columbia Circuit issued a decision that vacated the Clean

Air Mercury Rule. See New Jersey v. EPA, 517 F.3d 574 (D.C. Cir. 2008). Therefore,

CAMR requirements are not included in this Part 71 permit renewal. However,

mercury emissions from utility power plants are regulated under 40 CFR Part 63,

Subpart UUUUU (see below for discussion of applicable 40 CFR Part 63, Subpart

UUUUU requirements).

(f) This existing source is a major source for HAPs. The three boilers at this source (U1

through U3) are considered existing coal-fired electric generating units (EGUs) and

are subject to National Emission Standards for Hazardous Air Pollutants: Coal- and

Oil-Fired Electric Utility Steam Generating Units (40 CFR Part 63, Subpart UUUUU),

which were promulgated on February 16, 2012 and later revised on November 19,

2014.

Pursuant to 40 CFR § 63.9984(b), facilities subject to subpart UUUUU must comply

with the requirements of this NESHAP by April 16, 2015, unless they receive approval

for an extension to the compliance date under 40 CFR § 63.6(i). The permittee

requested an extension on the compliance date for the mercury provisions of this

NESHAP due to the technical difficulties associated with installing add-on mercury

controls. This extension request was granted by U.S. EPA and NNEPA on January 27,

2014. The extended compliance date for the mercury provisions is April 16, 2016. The

source must also comply with the following implementation schedule included in the

extension approval letter:

(1) By April 1, 2015, submit to NNEPA a title V permit modification application

that incorporates the final mercury control strategy. [Note: This permit

modification application was received on March 31, 2015]

(2) By October 1, 2015, commence construction to incorporate the mercury

control strategy on-site.

(3) By April 16, 2016, complete on-site construction and comply with all mercury

provisions of this NESHAP.

The permitee is also required to submit interim progress reports and a final report to

NNEPA and U.S. EPA.

The permittee shall comply with the following emission limits, pursuant to 40 CFR §

63.9991(a) and Table 2 of this NESHAP:

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(1) By April 16, 2015, filterable PM emissions shall not exceed 0.03 lb/MMBtu or

0.3 lb/MWh.

(2) By April 16, 2015, SO2 emissions shall not exceed 0.2 lb/MMBtu or 1.5

lb/MWh.

(3) By April 16, 2016, Mercury (Hg) emissions shall not exceed 1.2 lb/TBtu or

0.013 lb/GWh.

The permitttee plans to use a combination of calcium bromide application and

powdered active carbon (PAC) injection system to control the Hg emissions from the

existing coal-fired boilers. Implementation of these control technologies will require

the installation of calcium bromide and PAC storage and handling equipment. The

construction and operation of this Hg control system is permitted under Tribal Minor

NSR Permit #T-0004-NN, issued on August 26, 2015.

In the permit application submitted on March 31, 2015, the permittee stated that they

will demonstrate compliance with the SO2 emission limit in this NESHAP using

CEMS and demonstrate compliance with the Hg emission limit using sorbent trap

monitoring system for each stack. The permittee plans to use PM CEMS to show

compliance with the filterable PM emissions limit under this NESHAP. However, the

newly installed PM CEMS are not currently working properly. The permittee

requested to conduct quarterly PM performance stack testing to show compliance with

the PM emission limit until such time the PM CEMS operate properly, which is

expected to occur in late 2015.

The associated compliance, monitoring, testing, notification, recordkeeping, and

reporting requirements are included in the permit as Attachment C. Please note that the

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

(g) Each of the boilers at this source (U1 through U3, AUXA, and AUXB) has a

maximum heat input greater than 250 MMBtu/hr. However, these boilers commenced

construction before August 17, 1971 and the permittee stated that no modification or

reconstruction to the boilers has occured since the construction of these boilers.

Therefore, the New Source Performance Standards (NSPS) for Fossil-Fuel-Fired

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

commenced construction or modification after August 17, 1971, are not applicable to

the boilers at this source.

(h) This existing source is a major source for HAPs. Boilers U1 throught U3 are subject

to NESHAP for Coal- and Oil-Fired Electric Utility Steam Generating Units (40 CFR

Part 63, Subpart UUUUU). Therefore, these three boilers are not subject to the

National Emission Standards for Hazardous Air Pollutants for Industrial,

Commercial, and Institutional Boilers and Process Heaters (40 CFR Part 63, Subpart

DDDDD), pursuant to 40 CFR § 63.7491(a). However, the No. 2 fuel oil-fired

auxiliary boilers (AUX A and AUX B) are subject to this NESHAP. According to the

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initial notification submitted by the permittee on May 30, 2013, the auxiliary boilers

operate less than 10% of the annual capacity and are considered “limited-use” units,

as defined in 40 CFR § 63.7575.

Pursuant to 40 CFR § 63.7500(c), limited-use boilers are only required to complete a

tune-up every 5 years. There are no specific emission limits, energy assessment, or

operating limits for these type of boilers. Pursuant to 40 CFR § 63.7495(b), the

compliance date for the existing affected units is January 31, 2016.

In addition, 40 CFR § 63.7555(d)(3) requires the permitting authority to include a

federally enforceable condition in the permittee’s Part 71 permit to limit the operation

of the auxiliar boilers (AUX A and AUX B) to not more than 10% of the annual

capacity for each unit, in order to ensure they continue to qualify for “limited-use”

unit status. The permittee has requested the inclusion of this opertating limit in the

Part 71 renewal permit.

(i) The coal handling operations at this source process more than 200 tons of coal per

day. However, all of the coal handling operations at this source commenced

construction before October 24, 1974 and the permittee stated that no modification to

the coal handling operations has occured since the construction of these units.

Therefore, pursuant to 40 CFR § 60.250, the requirements of the New Source

Performance Standards for Coal Preparation and Processing Plants (40 CFR Part 60,

Subpart Y) are not applicable.

(j) Lime is considered a nonmetallic mineral as defined in 40 CFR § 60.671. The

limestone handling system at this source commenced construction after August 31,

1983 and performs grinding operations. Therefore, pursuant to 40 CFR § 60.670, the

limestone handling system at this source is subject to the requirements of the New

Source Performance Standards (NSPS) for Nonmetallic Mineral Processing Plants

(40 CFR Part 60, Subpart OOO). The affected facilities include each grinding mill,

screening operation, belt conveyor, storage bin, and enclosed truck loading station

associated with the limestone handling system.

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

limitations:

(1) Emissions from any stack shall not exceed a PM limit of 0.05 g/dscm (0.022

gr/dscf) and an opacity limit of 7%.

(2) Fugitive emissions shall not exceed 10% opacity, except for crushers at which

a capture system is not used.

(3) Fugitive emissions from crushers at which a capture system is not used shall

not exceed 15% opacity.

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(4) Truck dumping of nonmetallic minerals into any screening operation, feed

hopper, or crusher is exempt from the requirements of 40 CFR § 60.672.

(5) If an affected facility is enclosed in a building, then each enclosed affected

facility must comply with the emission limits specified above, or the building

enclosing any affected facility shall not emit any fugitive emissions exceeding

7% opacity or any emissions from a vent exceeding a PM limit of 0.05 g/dscm

(0.022 gr/dscf).

(6) Stack emissions from any baghouse that controls emissions from only an

individual, enclosed storage bin shall not exceed 7 percent opacity.

The permittee shall also comply with the testing requirements in 40 CFR § 60.675

and the recordkeeping and reporting requirements in 40 CFR § 60.676.

(k) The emergency fire pump (NGS-120A) was manufactured as a certified National Fire

Protection Association (NFPA) fire pump engine after July 1, 2006. Therefore, this

unit is subject to the requirements of the New Source Performance Standards for

Stationary Compression Ignition Internal Combustion Engines (40 CFR Part 60,

Subpart IIII), pursuant to 40 CFR § 60.4200(a)(2)(ii). All other emergency generators

at this facility are not subject to these NSPS because they were either installed before

April 1, 2006 or are not stationary units.

The emergency fire pump (NGS-120A) has a maximum capacity of 300 hp and was

manufactured in 2010. The emissions from this unit shall comply with the following

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

(1) NMHC + NOX emissions shall not exceed 4.0 g/KW-hr or 3.0 g/HP-hr.

(2) PM emissions shall not exceed 0.2 g/KW-hr or 0.15 g/HP-hr.

Engine NGS-120A has a displacement less than 9 liters per cylinder. Pursuant to 40

CFR § 60.4207(b), the permittee must use diesel fuel that meets the requirements of

40 CFR § 80.510(b) for nonroad diesel fuel (ultra low sulfur diesel fuel), except that

any existing diesel fuel purchased (or otherwise obtained) prior to October 1, 2010,

may be used until depleted.

The permittee shall comply with the operating requirements specified 40 CFR §

60.4211(a) and the engine certification requirements in 40 CFR § 60.4211(c). There

are no initial notification requirements for this emergency fire pump, pursuant to 40

CFR § 60.4214(b).

(l) The emergency generators and fire pumps at this source are considered stationary

reciprocating internal combustion engines (RICE) and are subject to the NESHAP for

Stationary Reciprocating Internal Combustion Engines (40 CFR Part 63, Subpart

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ZZZZ). Stationary diesel generators EG1, EG2, EG3, NPG-746, and NGS-120A are

subject to this NESHAP. All the affected units are compression ignition engines (CI).

The applicable requirements for the affected units can be divided into the following

three categories:

(1) Units with no specific requirements:

For the existing emergency generators with capacities greater than 500 hp (EG1), the

permittee is not required to meet the requirements of this subpart and of 40 CFR 63,

Subpart A, pursuant to 40 CFR § 63.6590(b)(3)(iv). No initial notification is required.

(2) Units with specific requirements:

For the existing emergency generators with capacities equal to or less than 500 hp

(EG2, EG3, and NPG-746), the permittee shall comply with the following work

practice requirements specified in Table 2c of this subpart, pursuant to 40 CFR §

63.6602:

(1) Change oil and filter every 500 hours or annually;

(2) Inspect air cleaner every 1,000 hours or annually;

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

(4) Minimize the engine's time spent at idle and minimize the engine's startup

time to a period needed for appropriate and safe loading of the engine, not to

exceed 30 minutes, after which time the non-startup emission limitations

apply.

The initial compliance date for units EG2, EG3, and NPG-746 is May 3, 2013,

pursuant to 40 CFR § 63.6595(a).

(3) Units subjected to NSPS under 40 CFR Part 60, Subpart IIII:

The emergency fire pump (NGS-120A) is an emergency unit with a maximum

capacity less than 500 hp and is subject to the requirements of NSPS for Stationary CI

ICE, 40 CFR Part 60, Subpart IIII. For this unit, compliance with this NESHAP is

demonstrated by complying with the requirements specified in the NSPS for

Stationary CI ICE, 40 CFR Part 60, Subpart IIII, pursuant to 40 CFR § 63.6590(c).

The following table summarizes the capacity, construction date, unit category type,

and applicable requirements for each emergency generator subject to 40 CFR Part 63,

Subpart ZZZZ:

of 29

Unit ID Max. Capacity

(hp) Construction Date Unit Category

Subpart ZZZZ

Requirements EG1 515 before 12/19/2002 Existing RICE None EG2 280 before 06/12/2006 Existing RICE Work Practice EG3 70 before 06/12/2006 Existing RICE Work Practice NPG-746 469 before 06/12/2006 Existing RICE Work Practice NGS-120A 300 after 06/12/2006 New RICE Compliance

through

compliance with

40 CFR Part 63,

Subpart IIII

(m) Tank NGS-064-A is used to store gasoline. However, this tank commenced

construction in 1991. Therefore, pursuant to 40 CFR § 60.110, the New Source

Performance Standards for Storage Vessels for Petroleum Liquids for Which

Construction, Reconstruction, or Modification Commenced After June 11, 1973, and

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

(n) Tank NGS-064-A is used to store gasoline and commenced construction in 1991.

However, the maximum capacity of this tank is less than 40,000 gallons. Therefore,

pursuant to 40 CFR § 60.110a, the New Source Performance Standards for Storage

Vessels for Petroleum Liquids for Which Construction, Reconstruction, or

Modification Commenced After May 19, 1978 and Prior to July 23, 1984 (40 CFR

Part 60, Subpart Ka) are not applicable.

(o) The diesel storage tank NGS-075B has a maximum storage capacity greater than 75

cubic meters (19,813 gallons) and was constructed after July 23, 1984. Since the

diesel fuel stored in this tank has a maximum true vapor pressure of less than 3.5 kPa,

tank NGS-075B is exempt from the requirements of the New Source Performance

Standards for Volatile Organic Liquid Storage Vessels for Which Construction,

Reconstruction, or Modification Commenced After July 23, 1984 (40 CFR Part 60,

Subpart Kb), pursuant to 40 CFR § 60.110b(b). Therefore, the requirements of this

NSPS are not applicable.

(p) The parts washers at this source do not use halogenated HAP solvents. Therefore,

pursuant to 40 CFR § 63,460(a), these units are not subject to the requirements of the

NESHAP for Halogenated Solvent Cleaning (40 CFR Part 63, Subpart T).

(q) There are specific SO2, NOX, and CO emission limits (in lbs/MMBtu) for boilers U1

through U3. The FIP for this source (40 CFR § 49.5513) and the PSD Permit #AZ 08-

01, issued on November 20, 2008, require the source to install and operate CEMS to

ensure continuous compliance with the SO2, NOX, and CO emission limits. These

requirements have been incorporated into this part 71 renewal permit. Therefore, the

SO2, NOx, and CO emissions from boilers U1 through U3 are exempt from the

requirements of 40 CFR Part 64 (Compliance Assurance Monitoring (CAM)),

pursuant to 40 CFR § 64.2(b)(1)(vi).

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The FIP for this source (40 CFR § 49.5513) has specific PM emission limits for boilers

U1 through U3 and the CAM requirements used to apply to these units. However, the

permittee recently installed PM CEMS for each of the boilers U1, U2, and U3 to

demonstrate compliance with the PM emission limits specified in NESHAP, Subpart

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

emission limits in FIP, compliance with the PM emission limit for NESHAP, Subpart

UUUUU using the new PM CEMS is sufficient to demonstrate compliance with PM

emission limit in FIP. Therefore, the PM emissions from boilers U1 through U3 are

exempt from the CAM requirements, pursuant to 40 CFR § 64.2(b)(1)(vi). A permit

condition (Condition II.N) has been added to this Part 71 permit renewal to require the

operation of PM CEMS with the stacks associated with boilers U1, U2, and U3.

However, in an addendum to Title V renewal application received on March 31, 2015,

the permittee stated that PM CEMS are still not operating properly and requested the

existing CAM requirements stayed in the Part 71 renewal permit until such time the

PM CEMS are fully in operation. Therefore, the CAM requirements from the current

Part 71 permit are still included in the renewal permit. The CAM requirements

(included as Condition II.N of the renewal permit) are summarized in the table below

and will still apply until such time the PM CEMS operate properly:

Electrostatic

Precipitator

Wet Limestone

Scrubber

Wet Limestone

Scrubber

Wet Limestone

Scrubber

Indicator

Number of

chambers/fields in

service

Number of Spray

levels in service Wet limestone

scrubber exhaust

temperature

Wet limestone

scrubber on/off

Measurement

Approach

The number of

chambers/fields in

service is monitored

and logged on a

continuous basis.

The number of wet

limestone scrubber

spray levels in service

is monitored on a

continuous basis.

The wet

limestone

scrubber exhaust

temperatures are

monitored at the

absorber outlets

prior to the stack

using a J-type

thermocouple.

The wet limestone

scrubber on/off

signal is monitored

on a continuous

basis.

Indicator

Threshold

An excursion is

defined as follows:

When an ESP unit is

operating with more

than 3 chambers (18

fields) out of service

during normal

operation of the

boiler.

An excursion is

defined as follows:

When a ESP unit is

operating with more

than one chamber (6


and less than 2 spray

levels are operating in

the wet limestone

scrubber associated

with the same boiler,

during normal

operations of the

boiler.

An excursion is

defined as

follows: When

the wet limestone

scrubber exhaust

temperatures

exceed 1450F for

more than one

unit, on a 1-hour

average basis,

during normal

operation of the

boilers.

An excursion is

defined as follows:

When the wet

limestone scrubber

is bypassed for

more than one unit,

for at least 1 hour,

during normal

operation of the

boilers.

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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


during normal

operation of the

boiler.

An excursion is

defined as follows:

When a ESP unit is

operating with more

than one chamber (6


and less than 2 spray

levels are operating in

the wet limestone

scrubber associated

with the same boiler,

during normal

operations of the

boiler.

An excursion is

defined as follows:

When the wet

limestone scrubber

exhaust

temperatures

exceed 1450F for

more than one unit,

on a 1-hour

average basis,

during normal

operation of the

boilers.

An excursion is

defined as follows:

When the wet

limestone scrubber

is bypassed for

more than one

unit, for at least 1

hour, during

normal operation

of the boilers.

Monitoring

Frequency

Continuous Continuous The wet limestone

scrubber exhaust

temperature is

measured

continuously.

The wet limestone

scrubber on/off

signal is monitored

continuously.

Data

Collection

Procedures

The AVC status bits

are recorded by the

BHA WinDAC Data

Acquisition and

Control Software,

and supplemented

with operating logs.

The wet limestone

scrubber spray level

signal will be

recorded on a

continuous basis by the

data acquisition

handling system.

The wet limestone

scrubber exhaust

temperature will be

recorded as an

hourly average by a

data acquisition

handling system.

The wet limestone

scrubber on/off

signal will be

recorded on a

continuous basis

by the data

acquisition

handling system.

of 29

Electrostatic

Precipitator

Wet Limestone

Scrubber

Wet Limestone

Scrubber

Wet Limestone

Scrubber

Averaging

Period Not Applicable Not Applicable 1-Hour average Not Applicable

There are no specific PM/PM10 emission limitations for the coal handling operations

or the ash handling operations. Therefore, pursuant to 40 CFR § 64.2(a), the

requirements of 40 CFR Part 64 (CAM) are not applicable to these units.

The limestone handling operations at this source are subject to the PM emission limit

in 40 CFR Part 60, Subpart OOO. The control devices associated with the limestone

handling operations are baghouses DC-9, DC-10, and DC-11. The pre-control PTE of

baghouse DC-9, DC-10, and DC-11 is each less than the major source threshold of 100

tons/yr. Therefore, pursuant to 40 CFR § 64.2(a), these baghouses are not subject to 40

CFR Part 64 (CAM).

(r) The permittee is subject to the requirements of the Asbestos NESHAP (40 CFR Part

61, Subpart M). The applicable requirements are specified in the permit document.

(s) The permittee is subject to the requirements of 40 CFR Part 82 (Protection of

Stratospheric Ozone). The applicable requirements are specified in the permit

document.

Summary of Applicable Federal Requirements

Federal Air Quality Requirement Current or Future

Requirement

Federal Implementation Plan for NGS (40 CFR §

49.5513)

Current

Acid Rain Regulations (40 CFR Parts 72-78) Current

CAM Requirements (40 CFR Part 64) Current

(until PM CEMS operate properly)

Visibility FIP (40 CFR § 52.145(d)) Current

NSPS for Nonmetallic Mineral Processing Plants (40

CFR Part 60, Subpart OOO) Current

NSPS for Stationary Compression Ignition Internal

Combustion Engines (40 CFR Part 60, Subpart IIII) Current

NESHAP for Coal- and Oil-Fired Electric Utility

Steam Generating Units (40 CFR Part 63, Subpart

UUUUU)

Current

NESHAP for Industrial, Commercial, and Institutional

Boilers and Process Heaters (40 CFR 63, Subpart

DDDDD)

Current

NESHAP for Stationary Reciprocating Internal

Combustion Engines (40 CFR Part 63, Subpart ZZZZ) Current

Asbestos NESHAP (40 CFR Part 61, Subpart M) Current

of 29

Federal Air Quality Requirement Current or Future

Requirement

Protection of Stratospheric Ozone (40 CFR Part 82) Current

Regional Haze BART Requirements (40 CFR §

51.308)

Current

(Included in the NGS FIP)

5. Additional Requirement

(a) In order to demonstrate compliance with 40 CFR Part 60, Subpart OOO for the

existing limestone handling system, a reopening permit was issued on November 13,

2003 and included the following testing, monitoring, and recordkeeping requirements

for baghouses DC-9, DC-10, and DC-11, which are used to control the emissions

from the limestone handling system:

(1) Stack testing for particulate matter emissions from the exhaust stacks of

baghouses DC-9, DC-10, and DC-11 shall be conducted once every five (5)

years using EPA Method 5 or Method 17. In addition, if during any twelve

(12) consecutive month period visible emissions are observed three times

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

baghouse within 120 days of the third observation.

(2) The permittee shall conduct a weekly visual emission survey of the exhaust

stacks of baghouses DC-9, DC-10, and DC-11 while the equipment is

operating and during daylight hours, by a person certified in EPA Method 9. If

any visible emissions are observed, the permittee shall conduct an opacity test

using EPA Method 9 within 24 hours while the equipment is operating in

accordance with 40 CFR § 60.675.

(3) The permittee shall record and maintain the following records for each visible

emission observation or Method 9 opacity test:

(i) the date and time of the observation and the name of the observer;

(ii) the unit ID number;

(iii) a statement of whether visible emissions were detected, and if so,

whether they were observed continuously or intermittently; and

(iv) the results of the Method 9 test, if required.

(b) Pursuant to Tribal Minor NSR Permit #T-0004-NN, issued on August 26, 2015, the

permittee shall comply with the following requirements for the new mercury emission

control system (including a new powdered activated carbon (PAC) injection system

and a new calcium bromide application system):

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

of 29

PAC shall not exceed 30 VMT per 12-month period.

(2) VMT for truck traffic associated with the delivery of calcium bromide shall

not exceed 365 VMT per 12-month period.

(3) The permittee shall monitor and maintain records on a calendar month basis of

each PAC deliver, the VMT of each delivery, and determine the 12-month

rolling total.

(4) The permittee shall monitor and maintain records on a calendar month basis of

each calcium bromide deliver, the VMT of each delivery, and determine the

12-month rolling total.

(5) At least once during each calendar week, the permittee shall perform a visible

emissions survey for each PAC silo (Silos A and B). The survey shall be

performed during daylight hours by an individual trained in EPA Method 22

while the equipment is in operation. If visible emissions are detected during

the survey, the permittee shall take corrective action so that within 24 hours

no visible emissions are detected.

6. Endangered Species Act

Pursuant to Section 7 of the Endangered Species Act (ESA), 16 U.S.C. § 1536, and its

implementing regulations at 50 CFR Part 402, USEPA is required to ensure that any action

authorized, funded, or carried out by USEPA is not likely to jeopardize the continued existence

of any Federally-listed endangered species or threatened species or result in the destruction or

adverse modification of such species’ designated critical habitat. NNEPA is issuing this federal

Part 71 permit pursuant to a delegation from USEPA. However, this permit does not authorize

the construction of new emission units or emission increases from existing units, nor does it

otherwise authorize any other physical modifications to the facility or its operations. Therefore,

NNEPA and USEPA have concluded that the issuance of this permit will have no effect on listed

species or their critical habitat.

7. Use of All Credible Evidence

Determinations of deviations from, continuous or intermittent compliance with, or violations of

the permit are not limited to the testing or monitoring methods required by the underlying

regulations or this permit; other credible evidence (including any evidence admissible under the

Federal Rules of Evidence) must be considered by the source, NNEPA, and U.S. EPA in such

determinations.

8. NNEPA Authority

Authority to administer the Part 71 Permit Program was delegated to the Navajo Nation EPA

by USEPA Region IX in part on October 13, 2004 and in whole on March 21, 2006. This

permit is issued pursuant to the May 2005 Voluntary Compliance Agreement between the

of 29

permittee and the Navajo Nation, which provided for Navajo regulation of NGS for CAA

purposes. The permittee shall comply with the terms of this permit and shall be subject to

enforcement of the permit by the Navajo Nation EPA and USEPA, pursuant to the terms of the

Voluntary Compliance Agreement. The permittee’s agreement to comply is effective upon the

permittee’s written acceptance of the permit and expires at the end of the permit term, unless

the permit is renewed. The permittee’s agreement to comply may be withdrawn during the

permit term only if the Voluntary Compliance Agreement is terminated or expires as provided

in that Agreement.

9. Public Participation

a. Public Notice

As required by NNOPR § 403(A), this permit renewal is being publicly noticed and

made available for public comment. The content, methods, and timing of public notice

are described in NNOPR § 403(B)-(D), and include a 30- day public comment period.

See also 40 CFR § 71.11(d) (equivalent public notice and comment provisions).

Public notice of this proposed permit action will be provided by mailing a copy of the

notice to the permittee, U.S. EPA Region 9, and the affected states (Utah and Arizona).

A copy of the notice will also be provided to all persons who submit a written request

to be included on the mailing list to the following individual:

Tennille Begay

Navajo Nation Operating Permit Program

P.O. Box 529


E-mail: [email protected]

Public notice will be published in a daily or weekly newspaper of general circulation in

the area affected by this source.

b. Opportunity for Comment

Members of the public may review a copy of the draft permit prepared by NNEPA, this

statement of basis for the draft permit, the application, and all supporting materials

submitted by the source at:

Navajo Nation Air Quality Control Program

Route 112 North, Bldg No. F004-51


Copies of the draft permit and this statement of basis can also be obtained free of

charge from NNEPA’s website:


of 29

www.navajonationepa.org/airqty/permits

or by contacting Tennille Begay at the NNAQCP address listed above or by telephone

at (928) 729-4248. All documents will be available for review at the NNAQCP office

indicated above during regular business hours.

If you have comments on the draft permit, you must submit them during the 30-day

public comment period. All comments received during the public comment period and

all comments made at any public hearing will be considered in arriving at a final

decision on the permit. The final permit is a public record that can be obtained by

request. A statement of reasons for any changes made to the draft permit and responses

to comments received will be sent to persons who commented on the draft permit.

If you believe that any condition of the draft permit is inappropriate, you must raise all

reasonably ascertainable issues and submit all arguments supporting your position by

the end of the comment period. Any supporting documents must be included in full and

may not be incorporated by reference, unless they are already part of the administrative

record for this permit or consist of tribal, state or federal statutes or regulations or other

generally available referenced materials.

Any comments on the acid rain permit shall be submitted to US EPA at the following

address:

EPA Region 9

75 Hawthorne Street


E-mail: [email protected]

c. Opportunity to Request a Hearing

A person may submit a written request for a public hearing to Tennille Begay, at the

address listed in Section 9(a) above, by stating the nature of the issues to be raised at

the public hearing. Based on the number of hearing requests received, NNEPA will

hold a public hearing whenever it finds there is a significant degree of public interest in

a draft operating permit. If a public hearing is held, NNEPA will provide public notice

of the hearing and any person may submit oral or written statements and data

concerning the draft permit.

d. Mailing List

If you would like to be added to NNEPA’s mailing list to be informed of future actions

on this or other Clean Air Act permits issued on the Navajo Nation, please send your

name and address to Tennille Begay at the address listed in Section 9(a) above.

http://www.navajonationepa.org/title5permits.html

of 16 SOB App AAppendix A: Emission Calculations

Criteria Pollutant Emissions from the Coal Fired Boiler U1

Company Name: Navajo Generating StationAddress: 5 miles east of Page, off U.S. Highway 98, Page, AZ 86040

Permit No.: NN-OP-15-06Reviewer: ERG/YC

Date: September 4, 2015

Max. Heat Input Capacity

Ash Content (A)13.5 % (provided by the source)

PMa PM10b PM2.5b SO2c NOX

d VOCe COd

Emission Factor 0.06 0.729 0.324 0.10 0.24 0.05 0.15 (0.054A) (0.024A)

(lbs/MMBtu) (lbs/ton) (lbs/ton) (lbs/MMBtu) (lbs/MMBtu) (lbs/ton) (lbs/MMBtu)

Potential to Emit in (tons/yr) 1,947 1,097 488 3,246 7,789 75.3 4,868

a PM emission factor is the emission limit in 40 CFR 49.5513(d)(2). b PM10 and PM2.5 emission factors are from AP-42, Table 1.1-6 (09/98) for ESP control. c The SO2 emission factor is based on the emission limit in 40 CFR 52.145(d).d The NOX and CO emission factors are based on the emission limits in the PSD Permit AZ 08-01A, issued on 2/8/12.e VOC emission factor is from AP-42, Tables 1.1-19 (09/98).The heating value of the coal used at this plant is 21.562 MMBtu/ton, provided by the source.

Methodology

PTE of PM10, PM2.5, and VOC (tons/yr) = Max. Heat Input (MMBtu/hr) / 21.562 MMBtu/ton x Emission Factor (lbs/ton) x 8760 hrs/yr x 1 ton/2,000 lbsPTE of PM, SO2, NOx and CO (tons/yr) = Max. Heat Input (MMBtu/hr) x Emission Factor (lbs/MMBtu) x 8760 hr/yr x 1 ton/2,000 lbs

Pollutant

MMBtu/hr

7,410









d VOCe COd





Methodology


Pollutant

MMBtu/hr

7,410

of 16 SOB APP AAppendix A: Emission Calculations

HAP EmissionsFrom the Coal Fired Boilers U1 through U3




Emission Unit: Boiler U1 Boiler U2 Boiler U3Max. 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-06Total PCDF 1.09E-09 (lbs/ton) 1.64E-06 1.64E-06 1.64E-06Total PAH 2.08E-05 (lbs/ton) 0.03 0.03 0.03

Acetaldehyde 5.70E-04 (lbs/ton) 0.86 0.86 0.86Acetophenone 1.50E-05 (lbs/ton) 0.02 0.02 0.02

Acrolein 2.90E-04 (lbs/ton) 0.44 0.44 0.44Benzene 1.30E-03 (lbs/ton) 1.96 1.96 1.96

Benzyl Chloride 7.00E-04 (lbs/ton) 1.05 1.05 1.05DEHP 7.30E-05 (lbs/ton) 0.11 0.11 0.11

Bromoform 3.90E-05 (lbs/ton) 0.06 0.06 0.06Carbon Disulfide 1.30E-04 (lbs/ton) 0.20 0.20 0.20

2-Chloroacetophenone 7.00E-06 (lbs/ton) 0.01 0.01 0.01Chlorobenzene 2.20E-05 (lbs/ton) 0.03 0.03 0.03

Chloroform 5.90E-05 (lbs/ton) 0.09 0.09 0.09Cumene 5.30E-06 (lbs/ton) 0.01 0.01 0.01Cyanide 2.50E-03 (lbs/ton) 3.76 3.76 3.76

2,4-Dinitrotoluene 2.80E-07 (lbs/ton) 0.00 0.00 0.00Dimethyl Sulfate 4.80E-05 (lbs/ton) 0.07 0.07 0.07Ethyl Benzene 9.40E-05 (lbs/ton) 0.14 0.14 0.14Ethyl Chloride 4.20E-05 (lbs/ton) 0.06 0.06 0.06

Ethylene Dichloride 4.00E-05 (lbs/ton) 0.06 0.06 0.06Ethylene Dibromide 1.20E-06 (lbs/ton) 0.00 0.00 0.00

Formaldehyde 2.40E-04 (lbs/ton) 0.36 0.36 0.36Hexane 6.70E-05 (lbs/ton) 0.10 0.10 0.10

Isophorone 5.80E-04 (lbs/ton) 0.87 0.87 0.87Methyl Bromide 1.60E-04 (lbs/ton) 0.24 0.24 0.24Methyl Chloride 5.30E-04 (lbs/ton) 0.80 0.80 0.80

Methyl Hydrazine 1.70E-04 (lbs/ton) 0.26 0.26 0.26Methyl 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 0.05Methylene Chloride 2.90E-04 (lbs/ton) 0.44 0.44 0.44

Phenol 1.60E-05 (lbs/ton) 0.02 0.02 0.02Propionaldehyde 3.80E-04 (lbs/ton) 0.57 0.57 0.57

Tetrachloroethylene 4.30E-05 (lbs/ton) 0.06 0.06 0.06Toluene 2.40E-04 (lbs/ton) 0.36 0.36 0.36

1,1,1-Trichloroethane 2.00E-05 (lbs/ton) 0.03 0.03 0.03Styrene 2.50E-05 (lbs/ton) 0.04 0.04 0.04Xylenes 3.70E-05 (lbs/ton) 0.06 0.06 0.06

Vinyl Acetate 7.60E-06 (lbs/ton) 0.01 0.01 0.01Antimony 1.80E-05 (lbs/ton) 0.03 0.03 0.03Arsenic 4.10E-04 (lbs/ton) 0.62 0.62 0.62

Beryllium 2.10E-05 (lbs/ton) 0.03 0.03 0.03Cadmium 5.10E-05 (lbs/ton) 0.08 0.08 0.08Chromium 2.60E-04 (lbs/ton) 0.39 0.39 0.39

Chromium (VI) 7.90E-05 (lbs/ton) 0.12 0.12 0.12Cobalt 1.00E-04 (lbs/ton) 0.15 0.15 0.15Lead 4.20E-04 (lbs/ton) 0.63 0.63 0.63

Manganese 4.90E-04 (lbs/ton) 0.74 0.74 0.74Mercury* 1.20E-06 (lbs/MMBtu) 0.04 0.04 0.04

Nickel 2.80E-04 (lbs/ton) 0.42 0.42 0.42Selenium 1.30E-03 (lbs/ton) 1.96 1.96 1.96

Hydrogen Fluoride* 5.30E-05 (lbs/MMBtu) 1.72 1.72 1.72Hydrogen Chloride* 7.70E-05 (lbs/MMBtu) 2.50 2.50 2.50

Total 22.7 22.7 22.7Note: 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 lbsPTE of Hg, HF, and HCl (tons/yr) = Max. Heat Input (MMBtu/hr) x Emission Factor (lbs/MMBtu) x 8760 hr/yr x 1 ton/2,000 lbs


No. 2 Fuel Oil Combustion (MMBtu/hr > 100)

From Two (2) 308 MMBtu/hr Auxiliary Boilers




Max. Fuel Usage S = Weight % Sulfur Operation Hour Limit*(kgal/hr) (hrs/yr)

(each) 2.24 (each) 0.05 876

PollutantPM PM10 PM2.5 SO2 NOx VOC CO

Emission Factor in lbs/kgal 2.00 1.00 0.25 7.1 24.0 0.2 5.0 (142 S)

Potential to Emit in tons/yr for 2 units 3.92 1.96 0.49 13.9 47.1 0.39 9.81

Emission factors are from AP-42, Tables 1.3-1, 1.3-2, 1.3-3, and 1.3-6 (AP-42, 05/10).* Pursuant to 40 CFR 63.7555(d)(3) (NESHAP, Subpart DDDDD), limited use boilers means boilers that limit the annual capacity factor to less than or equal to 10 percent

Methodology

PTE (tons/yr) = Max. Fuel Usage (kgal/hr) x Emission Factor (lbs/kgal) x Operation Hour Limit (hrs/yr) x 1 ton/2000 lbs x 2 units

Heat Input Capacity

308

MMBtu/hr


HAP EmissionsFrom Two (2) 308 MMBtu/hr Auxiliary Boilers




Max. Fuel Usage Operation Hour Limit*(kgal/hr) (hrs/yr)

(each) 2.24 (each) 876

PollutantChloride 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 CapacityMMBtu/hr


PM, PM10, and PM2.5 Emissions From Coal Handling Operations




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 2.190Feeders 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 0.004Conveyor 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 0.002Conveyor 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 0.154Conveyor 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 0.001Conveyors 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 0.002Screens 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 0.002Conveyors 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 0.003Silos 1A through 1G 7 3,000 0.00014 4.60E-05 1.30E-05 Dust Collector/Baghouse 99.0% 0.129 0.042 0.012Silos 2A through 2G 7 3,000 0.00014 4.60E-05 1.30E-05 Dust Collector/Baghouse 99.0% 0.129 0.042 0.012Silos 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)


PM, PM10, and PM2.5 Emissions From the Coal Storage Piles (Fugitive Emissions)




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 PM2.5U = 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/tonPM 2.5 Emission Factor = 0.00005 lbs/ton

2. Potential to Emit PM/PM10/PM2.5 after Control:

Max. Throughput Rate: 3,300 tons/hr Control Efficiency : 50% for water suppression

PTE of PM after Control (tons/yr) = 3,300 tons/yr x 0.00075 lbs/ton x 8760 hr/yr x 1 ton/2000 lbs x (1-50%) = 5.43 tons/yr

PTE of PM10 after Control (tons/yr) = 3,300 tons/yr x 0.00036 lbs/ton x 8760 hr/yr x 1 ton/2000 lbs x (1-50%) = 2.57 tons/yr

PTE of PM2.5 after Control (tons/yr) = 3,300 tons/yr x 0.00005 lbs/ton x 8760 hr/yr x 1 ton/2000 lbs x (1-50%) = 0.39 tons/yr


PM, PM10, and PM2.5 Emissions From Limestone Handling System




Unit Description Number of Unit Max. Capacity (tons/hr)




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 0.03Feeders 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 0.05Ball 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.

MethodologyPTE 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% 67.4DC-10 0.001 17,950 0.15 0.67 99% 67.4DC-11 0.001 12,000 0.10 0.45 99% 45.1Total 1.80 180

MethodologyControlled Emissions (lbs/hr) = Grain Loading (gr/acfm) x Flow Rate (acfm) x 60 mins/hr x 1 lb/7000 grControlled Emissions (tons/yr) = Controlled Emissions (lbs/hr) x 8760 hrs/yr x 1 ton/2000 lbsUncontrolled 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/yrPTE of PM10 after Control = 1.19 tons/yr + 1.80 tons/yr = 2.98 tons/yrPTE of PM2.5 after Control = 1.19 tons/yr + 1.80 tons/yr = 2.98 tons/yr


PM, PM10, and PM2.5 Emissions From the Limestone Storage Piles (Fugitive Emissions)




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 PM2.5U = 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/tonPM2.5 Emission Factor = 0.0003 lbs/ton

2. Potential to Emit PM/PM10/PM2.5 after Control:

Max. Throughput Rate: 600 tons/yr Control Efficiency : 50% for water suppression

PTE of PM after Control (tons/yr) = 600 tons/yr x 0.0035 x 8760 hr/yr x 1 ton/2000 lbs x (1-50%) = 4.60 tons/yr

PTE of PM10 after Control (tons/yr) = 600 tons/yr x 0.0035 x 8760 hr/yr x 1 ton/2000 lbs x (1-50%) = 2.17 tons/yr

PTE of PM2.5 after Control (tons/yr) = 600 tons/yr x 0.0003 x 8760 hr/yr x 1 ton/2000 lbs x (1-50%) = 0.33 tons/yr


PM, PM10, PM2.5, and HAP Emissions From the Fly Ash Handling System




Unit Description Number of Units Max. Capacity (tons/hr/unit)





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 8.87Truck 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

HAPHAP

Concentration* (ton per ton ash)

PTE of HAP (tons/yr)

Beryllium 6.097E-06 1.78E-04Chromium 2.485E-05 7.25E-04Lead 2.650E-05 7.73E-04Manganese 1.372E-04 4.00E-03Nickel 2.893E-05 8.44E-04Total 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)


PM, PM10, and PM2.5 Emissions From the Soda Ash/Lime Handling Systems




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)


PTE of PM/PM10/PM2.5

after Control (tons/yr)

Soda Ash Silos 4 0.40 2.20 15.4 Dust Collector 99.0% 0.15Lime 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 lbsPTE of PM/PM10/PM2.5 after Control (tons/yr) = PTE of PM/PM10 before Control (tons/yr) x (1-Control Efficiency)


PM, PM10, and PM2.5 Emissions From the Cooling Towers




1. Process Description:

Circulation Flow Rate: 813,000 gal/min (6 cooling towers total)Total Drift: 0.0009% of the circulating flow (provided by the source)

Total Dissolved Solids: 12,000 ppm Density: 8.328 lbs/gal

% Not Deposited on Site: 10% (provided by the source)

2. Potential to Emit PM/PM10/PM2.5:

Assume PM emissions are equal to PM10 emissions.

PTE of PM/PM10/PM2.5 (Ibs/hr) = 813,000 gal/min x 60 min/hr x 0.0009% x 8.328 lbs/gal x 12,000 ppm x 1/1,000,000 ppm x 10% = 4.39 lbs/hr

PTE of PM/PM10/PM2.5 (tons/yr) = 4.40 lbs/hr x 8760 hrs/yr x 1 ton/2000 lbs = 19.2 tons/yr


Fugitive Emissions From Unpaved Roads




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 PM2.5a = empirical constant = 0.7 for PM, 0.9 for PM10, and 0.9 for PM2.5b = 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/milePM10 Emission Factor = 1.5 x (5.1/12)0.9 x (78.1/3)0.45 x (365-60)/365 = 2.52 lbs/milePM2.5 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 0.69Service/Fuel Truck 1 13.2 18.0 6,570 2.93% 0.39 32.0 8.3 0.83Ash Trucks 3 102 90.0 98,550 44.0% 44.8 480 124 12.4Ash Truck 1 102 12.0 4,380 1.95% 1.99 21.4 5.51 0.55D65 Dozer 1 22.0 5.00 1,825 0.81% 0.18 8.9 2.30 0.23D31 Dozer 1 8.00 2.00 730 0.33% 0.03 3.56 0.92 0.09Rubber Tire Dozer 1 33.5 1.00 365 0.16% 0.05 1.78 0.46 0.0513 -Yard Loader 1 72.0 7.00 2,555 1.14% 0.82 12.5 3.21 0.326-Yard Loader 1 24.0 2.00 730 0.33% 0.08 3.56 0.92 0.092.5-Yard Loaders 2 12.5 2.00 1,460 0.65% 0.08 7.12 1.84 0.187-Yard Loader 1 54.5 3.00 1,095 0.49% 0.27 5.34 1.38 0.148,000-Gallon Waterpulls 1 36.5 30.0 10,950 4.88% 1.78 53.4 13.8 1.3812,000-Gallon Waterpulls 1 115 127 46,355 20.7% 23.8 226 58.3 5.8312-Yard Crystallizer Trucks 3 13.0 2.00 2,190 0.98% 0.13 10.7 2.75 0.2812-Yard Dump Trucks 4 11.6 1.00 1,460 0.65% 0.08 7.12 1.84 0.1814G Grader 1 28.0 10.0 3,650 1.63% 0.46 17.8 4.59 0.46EI 300 Excavator 1 34.0 0.14 51 0.02% 0.01 0.25 0.06 0.01140H Grader 1 19.8 1.00 365 0.16% 0.03 1.78 0.46 0.05Road Trucks 2 11.0 1.00 730 0.33% 0.04 3.56 0.92 0.09724 Vac Truck 1 19.8 3.00 1,095 0.49% 0.10 5.34 1.38 0.142.5 Yar Loader (928) 3 12.5 2.00 2,190 0.98% 0.12 10.7 2.75 0.28NPG-797 Bucket Truck 1 20.6 40.0 14,600 6.51% 1.34 71.2 18.36 1.84NPG-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.

MethodologyComponent 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 UnitsPTE 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/yrPTE of PM10 after Control = 282 tons/yr x (1-50%) = 141 tons/yrPTE of PM2.5 after Control = 28.2 tons/yr x (1-50%) = 14.1 tons/yr

Total

Vehicle Type


Internal Combustion Engines

From the Diesel Emergency Generators




Operation Limit* (hrs/yr)

(9 units total) 500

PM PM10/PM2.5 SO2 NOx VOC COEmission 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 orbrief 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 OutputHorse Power (HP)

2,861


PTE Summary




Limited Potential To Emit after Control

Emission Units PM PM10 PM2.5 SO2 NOx VOC CO Total HAPs

Boiler U1 1,947 1,097 488 3,246 7,789 75.3 4,868 22.7Boiler U2 1,947 1,097 488 3,246 7,789 75.3 4,868 22.7Boiler U3 1,947 1,097 488 3,246 7,789 75.3 4,868 22.7Auxiliary Boilers 3.92 1.96 0.49 13.9 47.1 0.39 9.81 1.19Coal 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 - - - - 0.01Soda 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 NegligibleOther 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


Pursuant to the

Source-Specific

Federal Implementation Plan

40 CFR Part 49

Prepared By:

SALT RIVER PROJECT


P.O. Box 850

Page, AZ 86040

February 2015

Table of Contents

1. INTRODUCTION AND PURPOSE

2. FACILITY DETAILS

3. GEOGRAPHY AND CLIMATE

4. DUST SUPPRESSION METHODS

Federal Implementation Plan Requirements - 40 CFR Part 49 §49.24(d)(3)

4.1 ROADWAYS

4.2 MATERIAL STORAGE

4.3 COAL HANDLING

4.4 FLY ASH HANDLING

4.5 LIMESTONE HANDLING

Navajo Nation EPA Title V Permit # NN-ROP-05-06, Section II.D. NSPS Subpart OOO

5. INSPECTIONS

6. RECORDKEEPING AND REPORTING

7. ROADWAY EQUIPMENT

8. TRAINING

9. ATTACHMENTS

9.1 Facility Map

9.2 Weekly Inspection Forms

9.3 Visible Emissions Form

1.0 INTRODUCTION AND PURPOSE

Salt River Project’s (SRP’s) Navajo Generating Station (NGS) facility is committed to

responsible and sustainable stewardship of the environment; and compliance with the

requirements of the United States Environmental Protection Agency’s (EPA’s) Federal

Implementation Plan (FIP) for NGS, recorded in the Federal Register under 40 CFR Part 49. This

Dust Control Plan (DCP) describes methods and procedures to minimize emissions from point

and non-point dust sources and maintain compliance with the FIP.

FIP conditions in 40 CFR Part 49 §49.24(d)(3) specify that:

“Each owner or operator shall operate and maintain the existing dust suppression

methods for controlling dust from the coal handling and storage facilities. Within 90

days after promulgation of these regulations the owner or operator shall submit to the

Regional Administrator a description of the dust suppression methods for controlling

dust from the coal handling and storage facilities, fly ash handling and storage, and

road sweeping activities. Each owner or operator shall not emit dust with opacity

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

truck loading or unloading operation, or railcar unloading station.”

2.0 FACILITY DETAILS

NGS is a participant owned generating plant managed by SRP. NGS is located on leased land 5

miles southeast of Page Arizona at 4365 feet (elevation). The participants are U.S. Bureau of

Reclamation (24.3% ownership), Los Angeles Department of Water and Power (21.2%), Salt

River Project (21.7%), Arizona Public Service (14.0%), Nevada Power (11.3%) and Tucson

Electric Power Co. (7.5%). NGS is a three-unit coal fired power plant (supercritical design

tangentially-fired boilers) generating 2250 net megawatts of power.

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

electric rail to NGS. Coal is then transferred via enclosed conveyor systems for burning in the

boilers or stacked out to a storage pile for later use.

The management of coal combustion residues and the delivery of limestone for the SO2 scrubbers

is contracted to a third party entity but SRP remains the responsible party for truck loading and

unloading operations, material transfer, storage, and disposal activities. Coal combustion residues

include flyash, bottom ash, and scrubber byproducts. Bottom ash and scrubber byproducts are

handled in a wet state which minimizes the potential for dust emissions and these materials are

not addressed in the FIP and in this document.

3.0 GEOGRAPHY AND CLIMATE

NGS is located in an arid desert environment receiving an annual average of seven and half

inches of precipitation. The surrounding geologic formations include outcroppings of the Carmel

formation, Page Sandstone, and Navajo Sandstone. Weathering of these formations have created

substrates of unconsolidated aeolian sands and partially stabilized dune deposits with sparse

vegetation.

4.0 DUST SUPPRESSION METHODS

The FIP requires in 40 CFR Part 49 §49.24(d)(3) a description of the dust suppression methods

for coal handling and storage facilities, fly ash handling and storage, and road sweeping activities.

The tables contained in this section outline preventive and mitigating control measures as

guidelines to minimize dust emissions from paved and unpaved roads, storage piles, and the

material handling related to coal, fly ash, and limestone.

4.1 Roadways

Dust emissions from roadways are mitigated using control measures outlined below. Main

trafficked areas are sprayed with water daily (weather permitted) and speed limits are observed.

During winter months, ice formation may preclude water spraying due to safety consideration.

Roadway Non-Point Sources: One or more of the following control measures will be

implemented to minimize dust emissions from roadway sources.

TABLE 1.0 Control Measure Guidelines:

Source: Roadway Dust Control Measures

Paved Roads:

Traffic Activity

1. Water spray roads

2. Speed reduction

3. Limit Traffic

4. Sweeping of roads

Unpaved Roads:

Traffic Activity

1. Water spray roads

2. Speed reduction

3. Limit traffic

4. Gravel surface

5. Chemical stabilization

Carryout 1. Clean vehicles before entering roadway

2. Pave access road near plant site exit

3. Rapid cleanup after spill events

Monitor: Verify control measures weekly.

4.2 Material Storage

Table 2.0 Control Measure Guidelines:

Material Storage

Control techniques applicable to outdoor material storage piles fall into distinct categories

as related to handling operations (including traffic around piles) and mitigating wind

erosion. In both cases, the control can be achieved by implementing one or more of the

following strategies: (a) source extent reduction, (b) source improvement related to work

practices and transfer equipment (load-in and load-out operations), and (c) surface

treatments.

Material Disturbance and Wind Erosion Control Measures:

Source control 1. Minimize exposed surface area

2. Minimize surface disturbances and material handling

Source improvement 1. Reduce drop height when handling material

2. Maintain moisture and crust, as applicable

3. Shelter from wind, as applicable

Surface treatment 1. Water Spraying, as applicable



4.3 Coal Handling

SRP’s responsibilities extend to all aspects of coal handling and storage; this includes

implementing dust control measures for the following:

Coal Handling Non-Point Sources: One or more of the following control measures will be

implemented by NGS to minimize dust emissions from the potential sources listed below:


Source: (Unit ID) Material Handling Control Measures

Material Handling: (CT1)

Railroad car unloading

operations

1. Shelter from wind - enclosure

2. Reduce drop height – minimum hopper level

maintained

3. Watering spraying

(L1-L12) Twelve hopper

feeders


2. Water spraying


(BC-1) Belt Conveyor 1. Shelter from wind - enclosure

2. Water spraying


(BC-2) 1. Shelter from wind - enclosure

2. Maintain moisture





(BC-4A) 1. Shelter from wind - enclosure


(BFD-5A) 1. Shelter from wind - enclosure

Belt Feeder Deck 2. Maintain moisture



(BC-6A) 1 of 3 stacker /

reclaimer reversible

conveyers


2. Water spraying


(BC-6B) 2 of 3 stacker

conveyer only



(BC-6C) 3 of 3 stacker /

reclaimer reversible

conveyers



2. Water spraying


(BC-7) One conveyor to the

emergency reclaim hopper


2. Water spraying


Wind Erosion: (CS) Outdoor

coal storage piles


2. Water spraying



Coal Handling Point Sources: The potential sources listed in Table 4.0 utilize particulate control

devices to control emissions.

TABLE 4.0 Emission Control Devices:

Unit ID / Stack ID: Control Device Make / Size Stack Details

YSB-1 DC-8 (Sample Bldg

– 100 feet

elevation)

Peabody Lugar LT

(Air Flow

20,000 acfm)

Exit opening facing

eastward on east

side of EF-8.

Opening: 1.5 feet by

2 feet

BC-8A & BC-8B

BC-8A & BC-8B

screening operation

PSB-1 DE-5

(Cascade Enclosure

- 135 feet

elevation)

SIEMENS Dust

Eliminator System

Exit opening is

outside building

facing west.

Opening: 3 feet by 3

feet

BC-9A & BC-9B

BC-10A & BC-10B

CC-1A thru CC-9A;

CC-1B thru CC-9B;

BC-11A & BC-11B

SEE BELOW – The dust emissions from the cascading conveyors

are also controlled by DE-1 through DE-4 and DE-6 & DE-7.

Silos 1A thru 1G DE-1 & DE-2

(Cascade Enclosure

- 135 feet

elevation)

SIEMENS and

PR-1, SR-1 & EX-1

Exit opening is

outside building

facing east.

Opening: 3 feet by

3 feet


(Cascade Enclosure

- 135 feet

elevation)

SIEMENS and

PR-2, SR-2 & EX-2

Exit opening is

outside building

facing east.

Opening: 3 feet by

3 feet


(Cascade Enclosure

- 135 feet

elevation)

SIEMENS and

PR-3, SR-3 & EX-3

Exit opening is

outside building

facing east.

Opening: 3 feet by

3 feet

Monitor: Weekly visible emission observations will be recorded for each control device listed

above that is operating. If visible emissions are observed, opacity readings will be conducted in

accordance with EPA Method 9.

4.4 Fly Ash Handling

SRP’s responsibilities extend to all aspects of flyash handling and storage although some

activities are managed by a third party contractor:

Fly Ash Non-point Sources: The activities in Table 5.0 are managed by a third party contractor

and activities in Table 5.1 are managed by SRP. One or more of the following control measures

are implemented to minimize dust emissions from these potential sources.


Source: Material Handling and Roadway Control Measure(s)

Material Handling:

Silo 1 Loading

(open bed haul truck

loading operations)

1. Drop height reduction

2. Moisture retention, apply as needed

3. Wind sheltering, loading chute

Silo 2 Loading

(open bed haul truck

loading operations)




Paved Roads:

Traffic Activity

1. Limit Traffic


3. Water Flushing of roads


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


3. Speed reduction

4. Limit traffic

5. Gravel surface


Source: Material Handling/Processing Control Measure(s)

Spillage (conveyance from

post-furnace to enclosed silos)

1. Enclosure



Flyash Point Sources: The potential sources listed in Table 6.0 are managed by SRP and utilize

particulate control devices to control emissions.

TABLE 6.0 Emission Control Devices:


Silo 1

(storage activity)

DC-S1/2

(baghouse on top of

Silo 1)

Scientific Dust

Collectors

EX Fan facing

south on west end

of baghouse.

Opening: 2.5 feet

by 4 feet

Silo 2

(storage activity)

DC-S3

(baghouse on top of

Silo 2)

Scientific Dust

Collectors

EX Fan facing

south on west end

of baghouse.

Opening: 2.5 feet

by 4 feet

Silo 1 Loading

(enclosed fly ash

trucks loading)

DC-S1/2

(baghouse on top of

Silo 1)

Scientific Dust

Collectors

Facing skyward on

east side of

baghouse.

Opening: 1 foot by

2 feet

Silo 2 Loading

(enclosed fly ash

trucks loading)

DC-S3

(baghouse on top

Silo 2)

Scientific Dust

Collectors

EX Fan facing

south on west end

of baghouse.

Opening: 2.5 feet

by 4 feet

Monitor: Weekly visible emission observations will be recorded for each control device listed

above that is operating. If visible emissions are observed, opacity readings will be conducted in


4.5 Limestone Handling

All Limestone Non-Point and Point sources are managed in accordance with the NGS Title V

Operating Permit, Section II.D. NSPS, Subpart OOO requirements.

Limestone Handling Non-point Sources:

Table 7.0 Control Measure Guidelines:

Source: Control Measure(s)

Material Handling:

Unloading Bay A and B

(truck unloading operations)

Not Applicable - Truck dumping of non-metallic minerals into

any screening operation, feed hopper, or crusher is exempt

per 40 CFR 60.672(d)

LS – Limestone Storage Pile 1. Water suppression

2. Maintain visible surface crust

Monitor: Weekly observations will be recorded.

Limestone Handling Point Sources: The potential sources listed in Table 8.0 utilize particulate

control devices to control emissions.

Table 8.0 Control Devices:


O-LSH-HOP-A

DC-9

(Baghouse on SW

corner of

Limestone

Handling)

Mac Equipment

Company, Serial

number 95-

FMCF361Filter,

12X12X38.1 feet

tall, 22,000 pounds

and a design

capacity of 18,000

ACFM.

Facing skyward.

Opening: 34 inch

diameter pipe

O-LSH-FDR-A

O-LSH-CNV-A

O-LSH-HOP-B

DC-10

(Baghouse on NE

corner of

Limestone

Handling)

Mac Equipment

Company, Serial

number 96-

MCF361Filter,

12X12X38.1 feet

tall, 22,000 pounds

and a design

capacity of 18,000

ACFM.

Facing skyward.

Opening: 34 inch

diameter pipe

O-LSH-FDR-B

O-LSH-CNV-B

O-LSH-SILO-A&B

DC-11

(Baghouse on W

side of Limestone

Prep Building)

Mac Equipment

Company, Serial

number 95-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


Opacity limitations are as follows:

No greater than 15% from any crusher without a capture system.

No greater than 10% from any transfer point without a capture system.

No greater than 7% from any stack emissions or building vent enclosing any transfer

point or crushing operations.

Truck dumping of nonmetallic minerals into any screening operations, feed hopper or

crusher is exempt per 40 CFR 60.672(d).

4.5 Soda Ash and Lime Handling

All Soda Ash Point sources are managed in accordance with the FIP conditions in 40 CFR Part 49

§49.24(d)(3).

Soda Ash and Lime Handling Point Sources: The potential sources listed in Table 9.0 utilize

particulate control devices to control emissions.

Table 9.0

Control Devices:Unit

ID / Stack ID:

Control Device Make / Size Stack Details

SAB-1A, SAB-2A,

SAB-1B, SAB-2B

(water treatment

soda ash storage

activity)

DC-BH6

(baghouse on top of

Bin 3)

Scientific Dust

Collectors

Exhaust opening

facing south on top

of baghouse.

Opening: 6” I.D.

LB-1 & LB-2

(water treatment

lime storage activity)

DC-BH7

(baghouse on top of

Bin 1)

Scientific Dust

Collectors

Exhaust opening

facing south on top

of baghouse.

Opening: 6” I.D.


Opacity limitations are as follows:

No greater than 20% from any capture system.

5.0 INSPECTIONS

The effectiveness of control measures will be evaluated using regular inspections and

documentation of visible emissions, as applicable. Dust control devices will be operated and

maintained with opacity emission limits specified in the Federal Implementation Plan - 40 CFR

Part 49 §49.24(e)(8).

Inspections shall be performed weekly by trained and certified Method 9 observers. For non-

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

minimize dust emissions. In the case of point sources, the observers shall perform visible

emission observations. If visible emissions are observed, opacity readings will be conducted in


See Section 9 – Weekly Inspection Forms

6.0 RECORD KEEPING AND REPORTING

SRP will maintain records of weekly inspection records, Method 9 certification training, and

Method 9 observations.

SRP will make reports as necessary in accordance with the Federal Implementation Plan - 40

CFR Part 49 §49.24(f).

For excess emissions, SRP will notify the Navajo Environmental Protection Agency Director and

the U.S. Environmental Protection Agency Regional Administrator by telephone or in writing

within one business day.

The notifications will be sent to the Director, Navajo Environmental Protection Agency, by mail

to: P.O. Box 339, Window Rock, Arizona 86515, or by facsimile to: (928) 871–7996 (facsimile),

and to the Regional Administrator, U.S. Environmental Protection Agency Region 9, by mail to

the attention of Mail Code: AIR–5, at 75 Hawthorne Street, San Francisco, California 94105, by

facsimile to: (415) 947–3579 (facsimile), or by e-mail to:[email protected].

A complete written report of the incident shall be submitted to the Regional Administrator within

ten (10) working days after the event. This notification shall include the following information:

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

(ii) The magnitude of the excess emissions expressed in the units of the applicable emissions

limitation and the operating data and calculations used in determining the magnitude of the

excess emissions;

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

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

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

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

malfunction and the steps taken or planned to prevent the recurrence of such malfunction; and

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

7.0 ROADWAY EQUIPMENT

2 – Water Truck Owner: HRI Make: Komatsu, Model Mega, 13,000 gallon capacity

SRP RENTAL Make: International, Model 4300, 4,000 gallon capacity

1 – Water Pull

Owner: SRP Make: Caterpillar, Model 621-G, 8,000 gallon capacity

2 – Ride-On Sweeper

Owner: SRP Make: Tennet, Model 355-G, 14 cubic feet hopper volume

Owner: SRP Make: Tennet, Model 830, 3.4 cubic yard hopper volume

1 – Vacuum Truck

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

8.0 TRAINING

At least two (2) on-site personnel will obtain EPA Method 9 certifications and receiving training

regarding weekly inspections and provisions of this plan. A copy of the NGS FIP Dust Control

Plan will be made available to plant personnel and the third party contractor responsible for

handling coal combustion residues and limestone deliveries.

9.0 ATTACHMENTS

9.1 Facility Map

9.2 Weekly Inspection Forms

9.3 Visible Emissions Form

Facility Map

Weekly Inspection Forms

WEEKLY INSPECTION FORMS

NGS FIP WEEKLY OBSERVATIONS – 20% OPACITY LIMIT

Certified

Observer (Circle) Walter Begay Jon Adams LD Shakespear

Date: Signature:

SRP/NGS

Non-Point Sources (Coal Handling and Storage)

MATERIAL HANDLING AND STORAGE CONTROL MEASURES

Source (Unit ID) Control Measure(s) Implemented (Circle) Comments:

Material

Handling: (CT1)

Railroad car

unloading

operations


2. Reduce drop height – minimum hopper level

maintained

3. Water spraying

(L1-L12) Twelve

hopper feeders


2. Watering


(BC-1) Belt

Conveyor


2. Water spraying








(BC-4A) 1. Shelter from wind - enclosure


(BFD-5A)

Belt Feeder Deck





(BC-6A) 1 of 3

stacker / reclaimer

reversible

conveyers


2. Water spraying


(BC-6B) 2 of 3

stacker conveyer

only



(BC-6C) 3 of 3

stacker / reclaimer

reversible

conveyers


SRP/NGS

Non-Point Sources (Coal Handling and Storage)

MATERIAL HANDLING AND STORAGE CONTROL MEASURES

Source (Unit ID) Control Measure(s) Implemented (Circle) Comments:


2. Water spraying


(BC-7) One

conveyor to the

emergency reclaim

hopper


2. Water spraying


Wind Erosion:

(CS) Outdoor coal

storage piles

1. Maintain moisture or visible crust

2. Water spraying


Point Sources (Coal Handling and Storage)

PARTICULATE CONTROL DEVICES

Source (Unit ID) Control Device Is Control

Device

Operating?

(Check one)

Is there VE?

(Check one)

Was EPA

Method 09

conducted?

(Check one)

YES NO YES NO YES* NO**

YSB-1

DC-8 BC-8A & BC-8B

BC-8A & BC-8B

screening operation

PSB-1 DE-5

BC-9A & BC-9B

BC-10A & BC-10B

CC-6A/6B &

Silos 1A thru 1C

(coal silos)

DE-1

CC-4A/4B, CC-

5A/5B &

Silos 1D thru 1G

(coal silos)

DE-2

Cascade Enclosure PR-1 SR-1 EX-1

* Note: Complete one Method 9 VE Observation Form for each control device if visible emissions are

observed.

**Note: Method 9 VE Observation Form was not completed due to: Wind Direction / Sun Position / Other.

Explain:

SRP/NGS

Point Sources (Coal Handling and Storage - Continued)



Device

Operating?

(Check one)

Is there VE?

(Check one)

Was EPA

Method 09

conducted?

(Check one)


CC-3A/3B, CC-

11A/11B &

Silos 2A thru 1C

(coal silos)

DE-3

CC-1A/1B, CC-

2A/2B &

Silos 2D thru 1G

(coal silos)

DE-4


CC-7A/7B, CC-

8A/8B &

Silos 3A thru 1D

(coal silos)

DE-6

CC-9A/9B &

Silos 3E thru 1G

(coal silos)

DE-7


Point Sources (Fly Ash Handling and Storage)


Source (Unit ID) Control Device Is Control Device

Operating?

(Check one)

Is there VE?

(Check one)

Was EPA

Method 09

conducted?

(Check one)


Silo 1 (ash silo

storage) DC-S1/2

Silo 2 (ash silo

storage) DC-S3


observed.


Explain:

SRP/NGS

Point Sources (Fly Ash Handling and Storage)


Source Control Device Is Control Device

Operating?

(Check one)

Is there VE?

(Check one)

Was EPA

Method 09

conducted?

(Check one)


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


observed.


Explain:

Non-Point Sources (Fly Ash Handling and Storage)

MATERIAL HANDLING AND ROADWAY CONTROL MEASURES

Source Control Measure(s) Implemented (Circle) Comments:

Material

Handling:

Silo 1 Loading

(2 of 2 loading;

open bed haul truck

loading operations)




Silo 2 Loading

(2 of 2 loading;

open bed haul truck

loading operations)




Paved Roads:

Traffic Activity

1. Limit Traffic


3. Water Flushing of roads




Spillage 1. Reducing overloaded trucks

2. Wetting materials being hauled

Unpaved Roads:

Traffic Activity

1. Water suppression


3. Speed reduction

4. Limit traffic

5. Gravel surface

SRP/NGS

Non-Point Sources (Fly Ash Handling and Storage)

MATERIAL HANDLING AND ROADWAY CONTROL MEASURES


Spillage (conveyance from

post-furnace to

enclosed silos)

1. Enclosure


Non-Point Sources

PAVED ROADWAY CONTROL MEASURES


Paved Roads:

Traffic Activity

1. Water Spraying of Roads

2. Reduce Speed

3. Limit Traffic





Non-Point Sources

UNPAVED ROADWAY CONTROL MEASURES


Unpaved Roads:

Traffic Activity

1. Watering


3. Speed reduction

4. Limit traffic

5. Gravel surface

Point Sources (Soda Ash Handling and Storage)



Device

Operating?

(Check one)

Is there VE?

(Check one)

Was EPA

Method 09

conducted?

(Check one)


SAB-1A, SAB-2A,

SAB-1B, SAB-2B

(water treatment

soda ash storage

activity)

DE-BH6


observed.


Explain:

SRP/NGS

Point Sources (Lime Handling and Storage)



Device

Operating?

(Check one)

Is there VE?

(Check one)

Was EPA

Method 09

conducted?

(Check one)


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)


Source (Unit ID) Control Device (LIMT) Is Control Device

Operating?

(Check one)

Is there VE?

(Check one)

Was EPA

Method 09

conducted?

(Check one)


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)

MATERIAL HANDLING AND STORAGE MEASURES

Source CIRCLE Control Measures Implemented (LIMIT) Comments:

O-LSP-FDR-

A&B, O-LSP-

CNV-A&B

1. Enclosures - Pt. Src. Opacity Limits: From

baghouses, stacks and bldg. vents/openings 7%

2. Non-Enclosed - Fugitive Src. Opacity Limits: From

transfer pts. 10% / crushing 15%.

3. Dumping – Some activity is exempt

Limestone

Storage Pile (LS) 1. Watering

2. Maintain visible crust


observed.


Explain:

Visible Emissions Form

SRP/NGS VISIBLE EMISSION OBSERVATION FORM

Observation Date: _________________ Start Time: ______________ End Time: ___________

Process Equipment: LIMIT Process Control Device* (circle): Limestone Handling System

Title V Condition: II.D.5.ii & II.D.6 7% DC9 DC10 DC11 or Bldg. Vents

Coal Material Handling FIP Dust Control Plan Table 2.0

20% DE1 DE2 DE3 DE4 DE5 DE6 DE7 DC8

Fly Ash Handling / Storage FIP Dust Control Plan Table 3.0

20% DCS1/2 DCS3

Enclosed Trailer Loading FIP Dust Control Plan Table 7.0

20% DCS1/2 DCS3

Soda Ash and Lime Handling FIP Dust Control Plan Table 9.0

20% DEBH6 DEBH7

Plume Color: ______________ Plume Background: _________________ Sky: ________________

Wind Speed (mph): _________ Wind Direction (N-E-S-W): __________ Temperature (°F): _______

Stack Ht. - above 0 elev. (feet):_____Stack Distance and Ht. in relation to Observer (feet):________

Recording Observations. Opacity observations shall be recorded to the nearest 5 percent at 15-second intervals on an observational record sheet. A minimum of 24 observations shall be recorded. Each momentary observation recorded shall be deemed to represent the average opacity of emissions for a 15-second period. Data Reduction. Opacity shall be determined as an average of 24 consecutive observations recorded at 15-second intervals. Divide the observations recorded on the record sheet into sets of 24 consecutive observations. A set is composed of any 24 consecutive observations. Sets need not be consecutive in time and in no case shall two sets overlap. For each set of 24 observations, calculate the average by summing the opacity of the 24 observations and dividing this sum by 24. Record the average opacity on a record sheet.

Minute 0 second 15 sec 30 sec 45 sec Comments 1

2 3 4 5 6 Sum of opacity readings / 24 observations = Average opacity**

1

2 3 4 5 6 Sum of opacity readings / 24 observations = Average opacity**

*Note: Complete one sheet for one control device with emissions.

** Note: If Average Opacity is greater than LIMIT contact Paul Ostapuk and Operations IMMEDIATELY!

Observer: ___________________ Date:________________________________________

United States Environmental Protection Agency, Region IX

Air Division

75 Hawthorne Street


ACID RAIN PERMIT

Permit Number: NN 13-01

In accordance with the provisions of Title IV of the Clean Air Act and 40 C.F.R.

Parts 72 through 77, this Acid Rain Permit is issued to:

Salt River Project Agricultural Improvement and Power District

Navajo Generating Station (Plant Code 4941)

Page, AZ

All terms and conditions of the permit are enforceable by EPA and citizens under

the Clean Air Act. Please reference the permit number cited above in future

correspondence regarding this facility.

___________________________

Date Deborah Jordan

Director, Air Division

EPA Region IX

Acid Rain Permit No. NN 13-01

PERMIT CONDITIONS

1. The permittee shall comply with all the applicable requirements of the Acid Rain

Permit Application located in Appendix A.

2. The Permittee shall not discharge or cause the discharge of NOx from each

pulverized coal-fired boiler (U1, U2, and U3) into the atmosphere in excess of

0.40 lb/MMBtu of heat input on an annual average basis, calculated using the

methods and procedures specified in 40 CFR Part 75, Appendix F, Section 8.

3. This Acid Rain permit incorporates the definitions of terms in 40 CFR Part 72.2.

4. This permit is valid for a term of five (5) years from the date of issuance unless a

timely and complete renewal application is submitted to EPA at the following

address:

EPA Region IX

Permits Office (AIR-3)

75 Hawthorne St.


5. A timely renewal application is an application that is received at least six months

prior to the permit expiration date.

Acid Rain Permit No. NN 13-01

Appendix A

Acid Rain Permit Application

Attachment C - Page 1 of 24

Compliance, Monitoring, Testing, Notification, Recordkeeping, and Reporting Requirements under NESHAP, Subpart UUUUU for Coal- and Oil-Fired Electric Utility Steam Generating Units

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

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

I. GENERAL COMPLIANCE REQUIREMENTS

a. At all times you must operate and maintain any affected source, including associated air pollution control equipment and monitoring equipment, in a manner consistent with safety and good air pollution control practices for minimizing emissions. Determination of whether such operation and maintenance procedures are being used will be based on information available to the EPA Administrator which may include, but is not limited to, monitoring results, review of operation and maintenance procedures, review of operation and maintenance records, and inspection of the source. [40 CFR § 63.10000(b)]

b. If your coal-fired or solid oil derived fuel-fired EGU or IGCC EGU does not qualify as a LEE for total non-mercury HAP metals, individual non-mercury HAP metals, or filterable particulate matter (PM), you must demonstrate compliance through an initial performance test and you must monitor continuous performance through either use of a particulate matter continuous parametric monitoring system (PM CPMS), a PM CEMS, or, for an existing EGU, compliance performance testing repeated quarterly. [40 CFR § 63.10000(c)(1)(iv)]

c. If your EGU uses wet or dry flue gas desulfurization technology (this includes limestone injection into a fluidized bed combustion unit), you may apply a second alternative to HCl CEMS by installing and operating a sulfur dioxide (SO2) CEMS installed and operated in accordance with part 75 of this chapter to demonstrate compliance with the applicable SO2 emissions limit. [40 CFR § 63.10000(c)(1)(v)]

d. If your coal-fired EGU does not qualify as a LEE for Hg, you must demonstrate initial and continuous compliance through use of a sorbent trap monitoring system, in accordance with appendix A to this subpart. [40 CFR § 63.10000(c)(1)(vi)]

(1) You may choose to use separate sorbent trap monitoring systems to comply with this subpart: One sorbent trap monitoring system to demonstrate compliance with the numeric mercury emissions limit during periods other than startup or shutdown and the other sorbent trap monitoring system to report average mercury concentration during startup periods or shutdown periods.

(2) You may choose to use one sorbent trap monitoring system to demonstrate compliance with the mercury emissions limit at all times (including startup periods and shutdown periods) and to report average mercury concentration. You must follow the startup or shutdown requirements that follow and as given in Table 3 to this subpart for each 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 60


days before your initial performance evaluation (where applicable) of your CMS. This requirement also applies to you if you petition the Administrator for alternative monitoring parameters under 40 CFR § 63.8(f). This requirement to develop and submit a site-specific monitoring plan does not apply to affected sources with existing monitoring plans that apply to CEMS and CPMS prepared under appendix B to part 60 or part 75 of this chapter, and that meet the requirements of 40 CFR § 63.10010. Using the process described in 40 CFR § 63.8(f)(4), you may request approval of monitoring system quality assurance and quality control procedures alternative to those specified in 40 CFR § 63.10000(d)(1) and, if approved, include those in your site-specific monitoring plan. The monitoring plan must address the provisions in 40 CFR §§ 63.10000(d)(2) through (5). [40 CFR § 63.10000(d)(1)]

f. If requested by the Administrator, you must submit the monitoring plan (or relevant portion of the plan) at least 60 days before the initial performance evaluation of a particular CMS, except where the CMS has already undergone a performance evaluation that meets the requirements of 40 CFR § 63.10010 (e.g., if the CMS was previously certified under another program). [40 CFR § 63.10000(d)(3)]

g. You must operate and maintain the CMS according to the site-specific monitoring plan. [40 CFR § 63.10000(d)(4)]

h. The provisions of the site-specific monitoring plan must address the following items: [40 CFR § 63.10000(d)(5)]

(1) Installation of the CMS or sorbent trap monitoring system sampling probe or other interface at a measurement location relative to each affected process unit such that the measurement is representative of control of the exhaust emissions (e.g., on or downstream of the last control device).

(2) Performance and equipment specifications for the sample interface, the pollutant concentration or parametric signal analyzer, and the data collection and reduction systems.

(3) Schedule for conducting initial and periodic performance evaluations.

(4) Performance evaluation procedures and acceptance criteria (e.g., calibrations), including the quality control program in accordance with the general requirements of 40 CFR § 63.8(d).

(5) On-going operation and maintenance procedures, in accordance with the general requirements of 40 CFR §§ 63.8(c)(1)(ii), (c)(3), and (c)(4)(ii).

(6) Conditions that define a CMS that is out of control consistent with 40 CFR § 63.8(c)(7)(i) and for responding to out of control periods consistent with 40 CFR §§ 63.8(c)(7)(ii) and (c)(8).

(7) On-going recordkeeping and reporting procedures, in accordance with the general requirements of 40 CFR §§ 63.10(c), (e)(1), and (e)(2)(i), or as specifically required under Subpart UUUUU.

i. As part of your demonstration of continuous compliance, you must perform periodic tune-ups of your EGU(s), according to 40 CFR § 63.10021(e). [40 CFR § 63.10000(e)]


II. TESTING AND INITIAL COMPLIANCE REQUIREMENTS

a. For each of your affected EGUs, you must demonstrate initial compliance with each applicable emissions limit through performance testing. Where two emissions limits are specified for a particular pollutant (e.g., a heat input-based limit in lb/MMBtu and an electrical output-based limit in lb/MWh), you may demonstrate compliance with either emission limit. For a particular compliance demonstration, you may be required to conduct one or more of the following activities in conjunction with performance testing: collection of hourly electrical load data (megawatts); establishment of operating limits according to 40 CFR § 63.10011 and Tables 4 and 7 to Subpart UUUUU; and CMS performance evaluations. In all cases, you must demonstrate initial compliance no later than the applicable date in 40 CFR § 63.10005(f) for tune-up work practices for existing EGUs, in 40 CFR § 63.9984 for other requirements for existing EGUs, and in 40 CFR § 63.10005(g) for all requirements for new EGUs. [40 CFR § 63.10005(a)]

b. To demonstrate initial compliance using either a CMS that measures HAP concentrations directly (i.e., an Hg, HCl, or HF CEMS, or a sorbent trap monitoring system) or an SO2 or PM CEMS, the initial performance test consists of 30- (or, if emissions averaging for Hg is used, 90-) boiler operating days of data collected by the initial compliance demonstration date specified in 40 CFR § 63.9984(f) with the certified monitoring system. Pollutant emission rates measured during startup periods and shutdown period (as defined in 40 CFR § 63.10042) are not to be included in the compliance demonstration, except as otherwise provided in 40 CFR § 63.10000(c)(1)(vi)(B) and 40 CFR § 63.10000(a)(2)(iii). [40 CFR § 63.10005(a)(2)]

(1) The 30- (or, if applicable, 90-) boiler operating day CMS performance test must demonstrate compliance with the applicable Hg, HCl, HF, PM, or SO2 emissions limit in Table 1 or 2 to 40 CFR 63, Subpart UUUUU.

(2) You must collect hourly data from auxiliary monitoring systems (i.e., stack gas flow rate, CO2, O2, or moisture, as applicable) during the performance test period, in order to convert the pollutant concentrations to units of the standard. If you choose to comply with an electrical output-based emission limit, you must also collect hourly electrical load data during the performance test period.

c. CMS requirements. If, for a particular emission or operating limit, you are required to (or elect to) demonstrate initial compliance using a continuous monitoring system, the CMS must pass a performance evaluation prior to the initial compliance demonstration. If a CMS has been previously certified under another state or federal program and is continuing to meet the on-going quality-assurance (QA) requirements of that program, then, provided that the certification and QA provisions of that program meet the applicable requirements of 40 CFR §§ 63.10010(b) through (h), an additional performance evaluation of the CMS is not required under this subpart. [40 CFR § 63.10005(d)]

d. You may demonstrate initial compliance with the applicable SO2 emissions limit in Table 2 to this subpart through use of an SO2 CEMS installed and operated in accordance with part 75 of this chapter or appendix B to this subpart, as applicable. You may also demonstrate compliance with a filterable PM emission limit in Table 2 to this subpart through use of a PM CEMS installed, certified, and operated in accordance with 40 CFR § 63.10010(i). Initial compliance is achieved if the arithmetic average of 30-boiler operating days of quality-assured CEMS data, expressed in units of the standard (see 40 CFR § 63.10007(e)), meets the applicable SO2 or PM emissions limit in Table 2 to this subpart. Use Equation 19-19 of Method 19 in appendix A-7 to part 60 of this chapter to calculate the 30-boiler operating day average emissions rate. [40 CFR § 63.10005(d)(1)]


e. For affected EGUs that are either required to or elect to demonstrate initial compliance with the applicable Hg emission limit in Table 2 of this subpart using sorbent trap monitoring systems, initial compliance must be demonstrated no later than the applicable date specified in 40 CFR § 63.9984(f) for existing EGUs. Initial compliance is achieved if the arithmetic average of 30-boiler operating days of quality-assured sorbent trap monitoring system data, expressed in units of the standard (see section 6.2 of appendix A to this subpart), meets the applicable Hg emission limit in Table 2 to this subpart. [40 CFR § 63.10005(d)(3)]

f. All affected EGUs are subject to the work practice standards in Table 3 of 40 CFR Part 63, Subpart UUUUU. As part of your initial compliance demonstration, you must conduct a performance tune-up of your EGU according to 40 CFR § 63.10021(e). [40 CFR § 63.10005(e)]

g. For existing affected sources a tune-up may occur prior to April 16, 2012, so that existing sources employing neural network combustion controls, up to 54 calendar months (48 months from promulgation plus 180 days) after the date that is specified for your source in 40 CFR § 63.9984 and according to the applicable provisions in 40 CFR § 63.7(a)(2) as cited in Table 9 to this subpart to demonstrate compliance with this requirement. If a tune-up occurs prior to such date, the source must maintain adequate records to show that the tune-up met the requirements of this standard. [40 CFR § 63.10005(f)]

h. You must follow the startup and shutdown requirements given in Table 3 of 40 CFR Part 63, Subpart UUUUU. [40 CFR § 63.10005(j)]

i. You must submit a Notification of Compliance Status summarizing the results of your initial compliance demonstration, as provided in 40 CFR § 63.10030. [40 CFR § 63.10005(k)]

Subsequent performance tests and tune-ups

j. If you are required to meet an applicable tune-up work practice standard, you must conduct a performance tune-up according to 40 CFR § 63.10021(e). For EGUs employing neural network combustion optimization systems during normal operation, each performance tune-up specified in 40 CFR § 63.10021(e) must be no more than 48 calendar months after the previous performance tune-up. [40 CFR § 63.10006(i)(2)]

k. You must report the results of performance tests and performance tune-ups within 60 days after the completion of the performance tests and performance tune-ups. The reports for all subsequent performance tests must include all applicable information required in 40 CFR § 63.10031. [40 CFR § 63.10006(j)]

Methods and other procedures for the performance tests

l. Except as otherwise provided in this section, you must conduct all required performance tests according to 40 CFR §§ 63.7(d), (e), (f), and (h). You must also develop a site-specific test plan according to the requirements in 40 CFR § 63.7(c). [40 CFR § 63.10007(a)]

m. If you use CEMS (Hg, HCl, SO2, or other) to determine compliance with a 30- (or, if applicable, 90-) boiler operating day rolling average emission limit, you must collect quality- assured CEMS data for all unit operating conditions, including startup and shutdown (see 40 CFR § 63.10011(g) and Table 3 to 40 CFR 63, Subpart UUUUU), except as otherwise provided in 40 CFR § 63.10020(b). Emission rates determined during startup periods and shutdown periods (as defined in 40 CFR § 63.10042) are not to be included in the compliance determinations, except as otherwise provided in 40 CFR §§ 63.10000(c)(1)(vi)(B) and 63.10005(a)(2)(iii). [40 CFR § 63.10007(a)(1)]


n. You must conduct each performance test (including traditional 3-run stack tests, 30-boiler operating day tests based on CEMS data (or sorbent trap monitoring system data), and 30-boiler operating day Hg emission tests for LEE qualification) according to the requirements in Table 5 to Subpart UUUUU. [40 CFR § 63.10007(b)]

o. To use the results of performance testing to determine compliance with the applicable emission limits in Table 2 to Subpart UUUUU, proceed as follows: [40 CFR § 63.10007(e)]

(1) Except for a 30-boiler operating day performance test based on CEMS (or sorbent trap monitoring system) data, if measurement results for any pollutant are reported as below the method detection level (e.g., laboratory analytical results for one or more sample components are below the method defined analytical detection level), you must use the method detection level as the measured emissions level for that pollutant in calculating compliance. The measured result for a multiple component analysis (e.g., analytical values for multiple Method 29 fractions both for individual HAP metals and for total HAP metals) may include a combination of method detection level data and analytical data reported above the method detection level.

(2) If the limits are expressed in lb/MMBtu or lb/TBtu, you must use the F-factor methodology and equations in sections 12.2 and 12.3 of EPA Method 19 in appendix A-7 to part 60 of this chapter. In cases where an appropriate F-factor is not listed in Table 19-2 of Method 19, you may use F-factors from Table 1 in section 3.3.5 of appendix F to part 75 of this chapter, or F-factors derived using the procedures in section 3.3.6 of appendix to part 75 of this chapter. Use the following factors to convert the pollutant concentrations measured during the initial performance tests to units of lb/scf, for use in the applicable Method 19 equations:

(i) Multiply SO2 ppm by 1.66 × 10−7;

(ii) Multiply Hg concentrations (µg/scm) by 6.24 × 10−11.

(3) To determine compliance with emission limits expressed in lb/MWh or lb/GWh, you must first calculate the pollutant mass emission rate during the performance test, in units of lb/h. For Hg, if a CEMS or sorbent trap monitoring system is used, use Equation A-2 or 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 SO2, 9.43 × 10−8 lb/scf-ppm for HCl (if an HCl CEMS is used), 5.18 × 10−8 lb/scf-ppm for HF (if an HF CEMS is used), or 6.24 × 10−8 lb-scm/mg-scf for HAP metals and for HCl and HF (when performance stack testing is used), and defining Ch as the average SO2, HCl, or HF concentration in ppm, or the average HAP metals concentration in mg/dscm. This calculation requires stack gas volumetric flow rate (scfh) and (in some cases) moisture content data (see 40 CFR §§ 63.10005(h)(3) and 63.10010). Then, if the applicable emission limit is in units of lb/GWh, use Equation A-4 in appendix A to this subpart to calculate the pollutant emission rate in lb/GWh. In this calculation, define (M)h as the calculated pollutant mass emission rate for the performance test (lb/h), and define (MW)h as the average electrical load during the performance test (megawatts). If the applicable emission limit is in lb/MWh rather than lb/GWh, omit the 103 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, SO2, or PM emissions (or, if applicable, sorbent trap monitoring systems to continuously collect Hg emissions data), the following default values are available for use in the emission rate calculations during startup periods or shutdown periods (as defined in 40 CFR § 63.10042). For the purposes of this subpart, these default values are not considered to be substitute data. [40 CFR § 63.10007(f)]


(1) Diluent cap values. If you use CEMS (or, if applicable, sorbent trap monitoring systems) to comply with a heat input-based emission rate limit, you may use the following diluent cap values for a startup or shutdown hour in which the measured CO2 concentration is below the cap value or the measured O2 concentration is above the cap value:

(i) For an IGCC EGU, you may use 1% for CO2 or 19% for O2.

(ii) For all other EGUs, you may use 5% for CO2 or 14% for O2.

(2) Default electrical load. If you use CEMS to continuously monitor Hg, HCl, HF, SO2, or PM emissions (or, if applicable, sorbent trap monitoring systems to continuously collect Hg emissions data), the following default value is available for use in the emission rate calculations during startup periods or shutdown periods (as defined in 40 CFR § 63.10042). For the purposes of this subpart, this default value is not considered to be substitute data. For a startup or shutdown hour in which there is heat input to an affected EGU but zero electrical load, you must calculate the pollutant emission rate using a value equivalent to 5% of the maximum sustainable electrical output, expressed in megawatts, as defined in section 6.5.2.1(a)(1) of Appendix A to 40 CFR Part 75. This default electrical load is either the nameplate capacity of the EGU or the highest electrical load observed in at least four representative quarters of EGU operation. For a monitored common stack, the default electrical load is used only when all EGUs are operating (i.e., combusting fuel) are in startup or shutdown mode, and have zero electrical generation. Under those conditions, a default electrical load equal to 5% of the combined maximum sustainable electrical load of the EGUs that are operating but have a total of zero electrical load must be used to calculate the hourly electrical output-based pollutant emissions rate.

q. Upon request, you shall make available to the EPA Administrator such records as may be necessary to determine whether the performance tests have been done according to the requirements of 40 CFR § 63.10007. [40 CFR § 63.10007(g)]

r. You may use emissions averaging method as described in 40 CFR § 63.10009 to demonstrate compliance with the filterable PM, SO2, or Hg emission limits. [40 CFR § 63.10009]

s. You must comply with the applicable monitoring, installation, operation, and maintenance requirements specified in 40 CFR § 63.10010 for CEMS. [40 CFR § 63.10010]

t. You must demonstrate initial compliance with each emissions limit that applies to you by conducting performance testing. [40 CFR § 63.10011(a)]

u. If you use CEMS or sorbent trap monitoring systems to measure a HAP (e.g., Hg or HCl) directly, the first 30-boiler operating day (or, if alternate emissions averaging is used for Hg, the 90-boiler operating day) rolling average emission rate obtained with certified CEMS after the applicable date in §63.9984 (or, if applicable, prior to that date, as described in 40 CFR § 63.10005(b)(2)), expressed in units of the standard, is the initial performance test. Initial compliance is demonstrated if the results of the performance test meet the applicable emission limit in Table 2 to this subpart. [40 CFR § 63.10011(c)(1)]

v. For a unit that uses a CEMS to measure SO2 or PM emissions for initial compliance, the first 30 boiler operating day average emission rate obtained with certified CEMS after the applicable date in 40 CFR § 63.9984 (or, if applicable, prior to that date, as described in 40 CFR § 63.10005(b)(2)), expressed in units of the standard, is the initial performance test. Initial compliance is demonstrated if the results of the performance test meet the applicable SO2 or


filterable PM emission limit in Table 2 to 40 CFR Part 63, Subpart UUUUUU. [40 CFR § 63.10011(c)(2)]

w. You must submit a Notification of Compliance Status containing the results of the initial compliance demonstration, according to 40 CFR § 63.10030(e). [40 CFR § 63.10011(e)]

x. You must determine the fuel whose combustion produces the least uncontrolled emissions, i.e., the cleanest fuel, either natural gas or distillate oil, that is available on site or accessible nearby for use during periods of startup or shutdown. [40 CFR § 63.10011(f)(1)]

y. Your cleanest fuel, either natural gas or distillate oil, for use during periods of startup or shutdown determination may take safety considerations into account. [40 CFR § 63.10011(f)(2)]

z. You must follow the startup or shutdown requirements as given in Table 3 to subpart UUUUU for each coal-fired EGU. [40 CFR § 63.10011(g)]

(1) You may use the diluent cap and default electrical load values, as described in 40 CFR § 63.10007(f), during startup periods or shutdown periods.

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

(3) You must report the information as required in 40 CFR § 63.10031.

(4) If you choose to use paragraph (2) of the definition of “startup” in 40 CFR § 63.10042 and you find that you are unable to safely engage and operate your particulate matter (PM) control(s) within 1 hour of first firing of coal, you may choose to rely on paragraph (1) of definition of “startup” in 40 CFR § 63.10042 or you may submit a request to use an alternative non-opacity emissions standard, as described below.

(i) As mentioned in 40 CFR § 63.6(g)(1), the request will be published in the Federal Register for notice and comment rulemaking. Until promulgation in the Federal Register of the final alternative non-opacity emission standard, you shall comply with paragraph (1) of the definition of “startup” in 40 CFR § 63.10042. You shall not implement the alternative non-opacity emissions standard until promulgation in the Federal Register of the final alternative non-opacity emission standard.

(ii) The request need not address the items contained in 40 CFR § 63.6(g)(2).

(iii) The request shall provide evidence of a documented manufacturer-identified safely issue.

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

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

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


(B) The EGU has explicitly followed the manufacturer's procedures to alleviate or prevent the identified safety issue; and

(C) Identifies with specificity the details of the manufacturer's statement of concern.

(vi) The request shall specify the other work practice standards the EGU owner or operator will take to limit HAP emissions during startup periods and shutdown periods to ensure a control level consistent with the work practice standards of the final rule.

(vii) You must comply with all other work practice requirements, including but not limited to data collection, recordkeeping, and reporting requirements.

III. CONTINUOUS COMPLIANCE REQUIREMENTS

General compliance requirements

a. You must monitor and collect data according to this section and the site-specific monitoring plan required by 40 CFR § 63.10000(d). [40 CFR § 63.10020(a)]

b. You must operate the monitoring system and collect data at all required intervals at all times that the affected EGU is operating, except for periods of monitoring system malfunctions or out-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 monitoring system malfunctions and to return the monitoring system to operation as expeditiously as practicable. [40 CFR § 63.10020(b)]

c. You may not use data recorded during EGU startup or shutdown in calculations used to report emissions, except as otherwise provided in 40 CFR §§ 63.10000(c)(1)(vi)(B) and 63.10005(a)(2)(iii). In addition, data recorded during monitoring system malfunctions or monitoring system out-of-control periods, repairs associated with monitoring system malfunctions or monitoring system out-of-control periods, or required monitoring system quality assurance or control activities may not be used in calculations used to report emissions or operating levels. You must use all of the quality-assured data collected during all other periods in assessing the operation of the control device and associated control system. [40 CFR § 63.10020(c)]

d. Except for periods of monitoring system malfunctions or monitoring system out-of-control periods, repairs associated with monitoring system malfunctions or monitoring system out-of-control periods, and required monitoring system quality assurance or quality control activities including, as applicable, calibration checks and required zero and span adjustments), failure to collect required data is a deviation from the monitoring requirements. [40 CFR § 63.10020(d)]

e. During each period of startup, you must record the following for each EGU: [40 CFR § 63.10020(e)(1)]

(1) The date and time that clean fuels being combusted for the purpose of startup begins;

(2) The quantity and heat input of clean fuel for each hour of startup;

(3) The electrical load for each hour of startup;


(4) The date and time that non-clean fuel combustion begins; and

(5) The date and time that clean fuels being combusted for the purpose of startup ends.

f. During each period of shutdown, you must record the following for each EGU: [40 CFR § 63.10020(e)(2)]

(1) The date and time that clean fuels being combusted for the purpose of shutdown begins;

(2) The quantity and heat input of clean fuel for each hour of shutdown;

(3) The electrical load for each hour of shutdown;

(4) The date and time that non-clean fuel combustion ends; and

(5) The date and time that clean fuels being combusted for the purpose of shutdown ends.

g. For PM or non-mercury HAP metals work practice monitoring during startup periods, you must monitor and collect data according to 40 CFR § 63.10020 and the site-specific monitoring plan required by 40 CFR § 63.10011(l). [40 CFR § 63.10020(e)(3)]

Continuous compliance with the emission limitations, operating limits, and work practice standards

h. You must demonstrate continuous compliance with each emissions limit, operating limit, and work practice standard according to the monitoring specified in Table 7 to Subpart UUUUU and 40 CFR § 63.10021(b) through (g). [40 CFR § 63.10021(a)]

i. Except as otherwise provided in 40 CFR § 63.10020(c), if you use a CEMS to measure SO2, PM, HCl, HF, or Hg emissions, or using a sorbent trap monitoring system to measure Hg emissions, you must demonstrate continuous compliance by using all quality-assured hourly data recorded by the CEMS (or sorbent trap monitoring system) and the other required monitoring systems (e.g., flow rate, CO2, O2, or moisture systems) to calculate the arithmetic average emissions rate in units of the standard on a continuous 30-boiler operating day (or, if alternate emissions averaging is used for Hg, 90-boiler operating day) rolling average basis, updated at the end of each new boiler operating day. Use Equation 8 to determine the 30- (or, if applicable, 90-) boiler operating day rolling average. [40 CFR § 63.10021(b)]

Where:

Heri is the hourly emissions rate for hour i and n is the number of hourly emissions rate values collected over 30- (or, if applicable, 90-) boiler operating days.

j. If you must conduct periodic performance tune-ups of your EGU(s) as specified below and perform the first tune-up as part of your initial compliance demonstration. Notwithstanding this requirement, you may delay the first burner inspection until the next scheduled unit outage provided you meet the requirements of 40 CFR § 63.10005. Subsequently, you must perform an inspection of the burner at least once every 36 calendar months unless your EGU employs neural network combustion optimization during normal operations in which case you must perform an


inspection of the burner and combustion controls at least once every 48 calendar months. [40 CFR § 63.10021(e)]

(1) As applicable, inspect the burner and combustion controls, and clean or replace any components of the burner or combustion controls as necessary upon initiation of the work practice program and at least once every required inspection period. Repair of a burner or combustion control component requiring special order parts may be scheduled as follows:

(i) Burner or combustion control component parts needing replacement that affect the ability to optimize NOX and CO must be installed within 3 calendar months after the burner inspection,

(ii) Burner or combustion control component parts that do not affect the ability to optimize NOX and CO may be installed on a schedule determined by the operator;

(2) As applicable, inspect the flame pattern and make any adjustments to the burner or combustion controls necessary to optimize the flame pattern. The adjustment should be consistent with the manufacturer's specifications, if available, or in accordance with best combustion engineering practice for that burner type;

(3) As applicable, observe the damper operations as a function of mill and/or cyclone loadings, cyclone and pulverizer coal feeder loadings, or other pulverizer and coal mill performance parameters, making adjustments and effecting repair to dampers, controls, mills, pulverizers, cyclones, and sensors;

(4) As applicable, evaluate windbox pressures and air proportions, making adjustments and effecting repair to dampers, actuators, controls, and sensors;

(5) Inspect the system controlling the air-to-fuel ratio and ensure that it is correctly calibrated and functioning properly. Such inspection may include calibrating excess O2 probes and/or sensors, adjusting overfire air systems, changing software parameters, and calibrating associated actuators and dampers to ensure that the systems are operated as designed. Any component out of calibration, in or near failure, or in a state that is likely to negate combustion optimization efforts prior to the next tune-up, should be corrected or repaired as necessary;

(6) Optimize combustion to minimize generation of CO and NOX. This optimization should be consistent with the manufacturer's specifications, if available, or best combustion engineering practice for the applicable burner type. NOX optimization includes burners, overfire air controls, concentric firing system improvements, neural network or combustion efficiency software, control systems calibrations, adjusting combustion zone temperature profiles, and add-on controls such as SCR and SNCR; CO optimization includes burners, overfire air controls, concentric firing system improvements, neural network or combustion efficiency software, control systems calibrations, and adjusting combustion zone temperature profiles;

(7) While operating at full load or the predominantly operated load, measure the concentration in the effluent stream of CO and NOX in ppm, by volume, and oxygen in volume percent, before and after the tune-up adjustments are made (measurements may be either on a dry or wet basis, as long as it is the same basis before and after the adjustments are made). You may use portable CO, NOX and O2 monitors for this measurement. EGU's employing neural network optimization systems need only provide


a single pre- and post-tune-up value rather than continual values before and after each optimization adjustment made by the system;

(8) Maintain on-site and submit, if requested by the Administrator, an annual report containing the information in 40 CFR § 63.10021(e)(1) through (e)(9) including:

(i) The concentrations of CO and NOX in the effluent stream in ppm by volume, and oxygen in volume percent, measured before and after an adjustment of the EGU combustion systems;

(ii) A description of any corrective actions taken as a part of the combustion adjustment; and

(iii) The type(s) and amount(s) of fuel used over the 12 calendar months prior to an adjustment, but only if the unit was physically and legally capable of using more than one type of fuel during that period; and

(9) Report the dates of the initial and subsequent tune-ups as follows:

(i) If the first required tune-up is performed as part of the initial compliance demonstration, report the date of the tune-up in hard copy (as specified in 40 CFR § 63.10030) and electronically (as specified in 40 CFR § 63.10031). Report the date of each subsequent tune-up electronically (as specified in 40 CFR § 63.10031).

(ii) If the first tune-up is not conducted as part of the initial compliance demonstration, but is postponed until the next unit outage, report the date of that tune-up and all subsequent tune-ups electronically, in accordance with 40 CFR § 63.10031.

k. You must submit the reports required under 40 CFR § 63.10031 and, if applicable, the reports required under appendices A and B to Subpart UUUUU. The electronic reports required by appendices A and B to Subpart UUUUU must be sent to the Administrator electronically in a format prescribed by the Administrator, as provided in 40 CFR § 63.10031. CEMS data (except for PM CEMS and any approved alternative monitoring using a HAP metals CEMS) shall be submitted using EPA's Emissions Collection and Monitoring Plan System (ECMPS) Client Tool. Other data, including PM CEMS data, HAP metals CEMS data, and CEMS performance test detail reports, shall be submitted in the file format generated through use of EPA's Electronic Reporting Tool, the Compliance and Emissions Data Reporting Interface, or alternate electronic file format, all as provided for under 40 CFR § 63.10031. [40 CFR § 63.10021(f)]

l. You must report each instance in which you did not meet an applicable emissions limit or operating limit or failed to conduct a required tune-up. These instances are deviations from the requirements of Subpart UUUUU. These deviations must be reported according to 40 CFR § 63.10031. [40 CFR § 63.10021(g)]

m. You must follow the startup or shutdown requirements as given in Table 3 to subpart UUUUU. [40 CFR § 63.10021(h)]

(1) You may use the diluent cap and default electrical load values, as described in 40 CFR § 63.10007(f), during startup periods or shutdown periods.


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

(3) You must report the information as required in 40 CFR § 63.10031.

(4) You may choose to submit an alternative non-opacity emission standard, in accordance with the requirements contained in 40 CFR § 63.10011(g)(4). Until promulgation in the Federal Register of the final alternative non-opacity emission standard, you shall comply with paragraph (1) of the definition of “startup” in 40 CFR § 63.10042.

n. You must provide reports as specified in 40 CFR § 63.10031 concerning activities and periods of startup and shutdown. [40 CFR § 63.10021(i)]

Demonstrate continuous compliance under the emissions averaging provision

o. If the permittee elects to demonstrate compliance under the emissions averaging provision, the permittee must demonstrate compliance with this subpart on a continuous basis by meeting the requirements of 40 CFR §§ 63.1022(a)(1), (a)(4), and (b). [40 CFR § 63.10022]

IV. NOTIFICATION, REPORTS, AND RECORDS

Notifications Requirements

a. You must submit all of the notifications in §40 CFR § 63.7(b) and (c), 63.8 (e), (f)(4) and (6), and 63.9 (b) through (h) that apply to you by the dates specified. [40 CFR § 63.10030(a)]

b. When you are required to conduct a performance test, you must submit a Notification of Intent to conduct a performance test at least 30 days before the performance test is scheduled to begin. [40 CFR § 63.10030(d)]

c. When you are required to conduct an initial compliance demonstration as specified in 40 CFR § 63.10011(a), you must submit a Notification of Compliance Status according to 40 CFR § 63.9(h)(2)(ii). The Notification of Compliance Status report must contain all the information specified in 40 CFR § 63.10030(e)(1) through (8), as applicable. [40 CFR § 63.10030(e)]

(1) A description of the affected source(s) including identification of which subcategory the source is in, the design capacity of the source, a description of the add-on controls used on the source, description of the fuel(s) burned, including whether the fuel(s) were determined by you or EPA through a petition process to be a non-waste under 40 CFR 241.3, whether the fuel(s) were processed from discarded non-hazardous secondary materials within the meaning of 40 CFR 241.3, and justification for the selection of fuel(s) burned during the performance test.

(2) Summary of the results of all performance tests and fuel analyses and calculations conducted to demonstrate initial compliance including all established operating limits.

(3) Identification of whether you plan to demonstrate compliance with each applicable emission limit through performance testing; fuel moisture analyses; performance testing with operating limits (e.g., use of PM CPMS); CEMS; or a sorbent trap monitoring system.

(4) Identification of whether you plan to demonstrate compliance by emissions averaging.


(5) A signed certification that you have met all applicable emission limits and work practice standards.

(6) If you had a deviation from any emission limit, work practice standard, or operating limit, you must also submit a brief description of the deviation, the duration of the deviation, emissions point identification, and the cause of the deviation in the Notification of Compliance Status report.

(7) In addition to the information required in 40 CFR § 63.9(h)(2), your notification of compliance status must include the following:

(i) A summary of the results of the annual performance tests and documentation of any operating limits that were reestablished during this test, if applicable. If you are conducting stack tests once every 3 years consistent with 40 CFR § 63.10006(b), the date of the last three stack tests, a comparison of the emission level you achieved in the last three stack tests to the 50 percent emission limit threshold required in 40 CFR § 63.10006(i), and a statement as to whether there have been any operational changes since the last stack test that could increase emissions.

(ii) Certifications of compliance, as applicable, and must be signed by a responsible official stating:

(A) “This EGU complies with the requirements in 40 CFR § 63.10021(a) to demonstrate continuous compliance.” and

(B) “No secondary materials that are solid waste were combusted in any affected unit.”

(8) Identification of whether you plan to rely on paragraph (1) or (2) of the definition of “startup” in 40 CFR § 63.10042.

(i) Should you choose to rely on paragraph (2) of the definition of “startup” in 40 CFR § 63.10042 for your EGU, you shall include a report that identifies:

(A) The original EGU installation date;

(B) The original EGU design characteristics, including, but not limited to, fuel and PM controls;

(C) Each design PM control device efficiency;

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

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

(F) Each design PM control device efficiency upon startup of the PM control device;

(G) The design EGU uncontrolled PM emission rate in terms of pounds PM per hour;


(H) Each change from the original design that did or could have changed PM emissions, including, but not limited to, each different fuel mix, each revision to each PM control device, and each EGU revision, along with the month and year that the change occurred;

(I) Current EGU PM producing characteristics, including, but not limited to, fuel mix and PM controls;

(J) Current PM emission rate from the EGU in terms of pounds PM per MMBtu and pounds per hour;

(K) Current PM control device efficiency from each PM control device;

(L) Current time from start of fuel combustion to conditions necessary for each PM control device startup;

(M) Current PM control device efficiency upon startup of each PM control device; and

(N) Current EGU uncontrolled PM emission rate in terms of pounds PM per hour.

(ii) The report shall be prepared, signed, and sealed by a professional engineer licensed in the state where your EGU is located. Apart from preparing, signing, and sealing this report, the professional engineer shall be independent and not otherwise employed by your company, any parent company of your company, or any subsidiary of your company.

Reporting Requirements

d. You must submit each report in Table 8 to Subpart UUUUU that applies to you. If you are required to (or elect to) continuously monitor Hg and/or HCl and/or HF emissions, you must also submit the electronic reports required under appendix A and/or appendix B to the subpart, at the specified frequency. [40 CFR § 63.10031(a)]

e. Unless the Administrator has approved a different schedule for submission of reports under 40 CFR § 63.10(a), you must submit each report by the date in Table 8 to Subpart UUUUU and according to the requirements specified below: [40 CFR § 63.10031(b)]

(1) The first compliance report must cover the period beginning on the compliance date that is specified for your affected source in 40 CFR § 63.9984 and ending on June 30 or December 31, whichever date is the first date that occurs at least 180 days after the compliance date that is specified for your source in 40 CFR § 63.9984.

(2) The first compliance report must be postmarked or submitted electronically no later than July 31 or January 31, whichever date is the first date following the end of the first calendar half after the compliance date that is specified for your source in 40 CFR § 63.9984.

(3) Each subsequent compliance report must cover the semiannual reporting period from January 1 through June 30 or the semiannual reporting period from July 1 through December 31.


(4) Each subsequent compliance report must be postmarked or submitted electronically no later than July 31 or January 31, whichever date is the first date following the end of the semiannual reporting period.

(5) If the permitting authority has established dates for submitting semiannual reports pursuant to 40 CFR 70.6(a)(3)(iii)(A) or 40 CFR 71.6(a)(3)(iii)(A), you may submit the first and subsequent compliance reports according to the dates the permitting authority has established.

f. The compliance report must contain the information specified as follows: [40 CFR § 63.10031(c)]

(1) The information required by the summary report located in 40 CFR § 63.10(e)(3)(vi).

(2) The total fuel use by each affected source subject to an emission limit, for each calendar month within the semiannual reporting period, including, but not limited to, a description of the fuel, whether the fuel has received a non-waste determination by EPA or your basis for concluding that the fuel is not a waste, and the total fuel usage amount with units of measure.

(3) Indicate whether you burned new types of fuel during the reporting period. If you did burn new types of fuel you must include the date of the performance test where that fuel was in use.

(4) Include the date of the most recent tune-up for each unit subject to the requirement to conduct a performance tune-up according to 40 CFR § 63.10021(e). Include the date of the most recent burner inspection if it was not done every 36 (or 48) months and was delayed until the next scheduled unit shutdown.

(5) For each instance of startup or shutdown:

(i) Include the maximum clean fuel storage capacity and the maximum hourly heat input that can be provided for each clean fuel determined according to the requirements of 40 CFR § 63.10032(f).

(ii) Include the information required to be monitored, collected, or recorded according to the requirements of 40 CFR § 63.10020(e).

(iii) If you choose to use CEMS for compliance purposes, include hourly average CEMS values and hourly average flow rates. Use units of milligrams per cubic meter for PM CEMS, micrograms per cubic meter for Hg CEMS, and ppmv for HCl, HF, or SO2 CEMS. Use units of standard cubic meters per hour on a wet basis for flow rates.

(iv) If you choose to use a separate sorbent trap measurement system for startup or shutdown reporting periods, include hourly average mercury concentration in terms of micrograms per cubic meter.

(v) If you choose to use a PM CPMS, include hourly average operating parameter values in terms of the operating limit, as well as the operating parameter to PM correlation equation.

g. For each excess emissions occurring at an affected source where you are using a CMS to comply with that emission limit or operating limit, you must include the information required in 40


CFR § 63.10(e)(3)(v) in the compliance report specified 40 CFR § 63.10031(c). [40 CFR § 63.10031(d)]

h. You must report all deviations as defined in Subpart UUUUU in the semiannual monitoring report required by 40 CFR 70.6(a)(3)(iii)(A) or 40 CFR 71.6(a)(3)(iii)(A). If an affected source submits a compliance report pursuant to Table 8 to Subpart UUUUU along with, or as part of, the semiannual monitoring report required by 40 CFR 70.6(a)(3)(iii)(A) or 40 CFR 71.6(a)(3)(iii)(A), and the compliance report includes all required information concerning deviations from any emission limit, operating limit, or work practice requirement in Subpart UUUUU, submission of the compliance report satisfies any obligation to report the same deviations in the semiannual monitoring report. Submission of a compliance report does not otherwise affect any obligation the affected source may have to report deviations from permit requirements to the permit authority. [40 CFR § 63.10031(e)]

i. On or after April 16, 2017, within 60 days after the date of completing each performance test, you must submit the performance test reports required by this subpart to EPA's WebFIRE database by using the Compliance and Emissions Data Reporting Interface (CEDRI) that is accessed through EPA's Central Data Exchange (CDX) (www.epa.gov/cdx). Performance test data must be submitted in the file format generated through use of EPA's Electronic Reporting Tool (ERT) (see http://www.epa.gov/ttn/chief/ert/index.html). Only data collected using those test methods on the ERT Web site are subject to this requirement for submitting reports electronically to WebFIRE. Owners or operators who claim that some of the information being submitted for performance tests is confidential business information (CBI) must submit a complete ERT file including information claimed to be CBI on a compact disk or other commonly used electronic storage media (including, but not limited to, flash drives) to EPA. The electronic media must be clearly marked as CBI and mailed to U.S. EPA/OAPQS/CORE CBI Office, Attention: WebFIRE Administrator, MD C404-02, 4930 Old Page Rd., Durham, NC 27703. The same ERT file with the CBI omitted must be submitted to EPA via CDX as described earlier in this paragraph. At the discretion of the delegated authority, you must also submit these reports, including the confidential business information, to the delegated authority in the format specified by the delegated authority. [40 CFR § 63.10031(f)]

(1) On or after April 16, 2017, within 60 days after the date of completing each CEMS (SO2, PM, HCl, HF, and Hg) performance evaluation test, as defined in 40 CFR § 63.2 and required by this subpart, you must submit the relative accuracy test audit (RATA) data (or, for PM CEMS, RCA and RRA data) required by this subpart to EPA's WebFIRE database by using CEDRI that is accessed through EPA's CDX (www.epa.gov/cdx). The RATA data shall be submitted in the file format generated through use of EPA's Electronic Reporting Tool (ERT) (http://www.epa.gov/ttn/chief/ert/index.html). Only RATA data compounds listed on the ERT Web site are subject to this requirement. Owners or operators who claim that some of the information being submitted for RATAs is confidential business information (CBI) shall submit a complete ERT file including information claimed to be CBI on a compact disk or other commonly used electronic storage media (including, but not limited to, flash drives) by registered letter to EPA and the same ERT file with the CBI omitted to EPA via CDX as described earlier in this paragraph. The compact disk or other commonly used electronic storage media shall be clearly marked as CBI and mailed to U.S. EPA/OAPQS/CORE CBI Office, Attention: WebFIRE Administrator, MD C404-02, 4930 Old Page Rd., Durham, NC 27703. At the discretion of the delegated authority, owners or operators shall also submit these RATAs to the delegated authority in the format specified by the delegated authority. Owners or operators shall submit calibration error testing, drift checks, and other information required in the performance evaluation as described in 40 CFR § 63.2 and as required in this chapter.


(2) On or after April 16, 2017, for a PM CEMS, PM CPMS, or approved alternative monitoring using a HAP metals CEMS, within 60 days after the reporting periods ending on March 31st, June 30th, September 30th, and December 31st, you must submit quarterly reports to EPA's WebFIRE database by using the CEDRI that is accessed through EPA's CDX (www.epa.gov/cdx). You must use the appropriate electronic reporting form in CEDRI or provide an alternate electronic file consistent with EPA's reporting form output format. For each reporting period, the quarterly reports must include all of the calculated 30-boiler operating day rolling average values derived from the CEMS and PM CPMS.

(3) On or after April 16, 2017, submit the compliance reports required under 40 CFR § 63.10031(c) and (d) and the notification of compliance status required under 40 CFR § 63.10030(e) to EPA’s WebFIRE database by using the CEDRI that is accessed through EPA’s CDX (www.epa.gov/cdx). You must use the appropriate electronic reporting form in CEDRI or provide an alternate electronic file consistent with EPA's reporting form output format.

(4) On or after April 16, 2017, submit the compliance reports required under 40 CFR § 63.10031(c) and (d) and the notification of compliance status required under 40 CFR § 63.10030(e) to EPA's WebFIRE database by using the CEDRI that is accessed through EPA's CDX (www.epa.gov/cdx). You must use the appropriate electronic reporting form in CEDRI or provide an alternate electronic file consistent with EPA's reporting form output format.

(5) All reports required by this subpart not subject to the requirements in 40 CFR § 63.10030(f) introductory text and 40 CFR § 63.10031(f)(1) through (4) must be sent to the Administrator at the appropriate address listed in 40 CFR § 63.13. If acceptable to both the Administrator and the owner or operator of an EGU, these reports may be submitted on electronic media. The Administrator retains the right to require submittal of reports subject to 40 CFR § 63.10030(f) introductory text and 40 CFR § 63.10031(f)(1) through (4) in paper format.

(6) Prior to April 16, 2017, all reports subject to electronic submittal in 40 CFR § 63.10031(f) (f) introductory text, (f)(1), (2), and (4) shall be submitted to the EPA at the frequency specified in those paragraphs in electronic portable document format (PDF) using the ECMPS Client Tool. Each PDF version of a submitted report must include sufficient information to assess compliance and to demonstrate that the testing was done properly. The following data elements must be entered into the ECMPS Client Tool at the time of submission of each PDF file:

(i) The facility name, physical address, mailing address (if different from the physical address), and county;

(ii) The ORIS code (or equivalent ID number assigned by EPA's Clean Air Markets Division (CAMD)) and the Facility Registry System (FRS) ID;

(iii) The EGU (or EGUs) to which the report applies. Report the EGU IDs as they appear in the CAMD Business System;

(iv) If any of the EGUs in 40 CFR § 63.10031(f)(6)(iii) share a common stack, indicate which EGUs share the stack. If emissions data are monitored and reported at the common stack according to part 75 of this chapter, report the ID number of the common stack as it is represented in the electronic monitoring plan required under 40 CFR § 75.53 of this chapter;


(v) If any of the EGUs described in 40 CFR § 63.10031(f)(6)(iii) are in an averaging plan under §63.10009, indicate which EGUs are in the plan and whether it is a 30- or 90-day averaging plan;

(vi) The identification of each emission point to which the report applies. An “emission point” is a point at which source effluent is released to the atmosphere, and is either a dedicated stack that serves one of the EGUs identified in 40 CFR § 63.10031(f)(6)(iii) or a common stack that serves two or more of those EGUs. To identify an emission point, associate it with the EGU or stack ID in the CAMD Business system or the electronic monitoring plan (e.g., “Unit 2 stack,” “common stack CS001,” or “multiple stack MS001”);

(vii) The rule citation (e.g., 40 CFR § 63.10031(f)(1), § 63.10031(f)(2), etc.) for which the report is showing compliance;

(viii) The pollutant(s) being addressed in the report;

(ix) The reporting period being covered by the report (if applicable);

(x) The relevant test method that was performed for a performance test (if applicable);

(xi) The date the performance test was conducted (if applicable); and

(xii) The responsible official's name, title, and phone number.

j. If you had a malfunction during the reporting period, the compliance report must include the number, duration, and a brief description for each type of malfunction which occurred during the reporting period and which caused or may have caused any applicable emission limitation to be exceeded. [40 CFR § 63.10031(g)]

Records Keeping Requirements

k. You must keep records specified below. If you are required to (or elect to) continuously monitor Hg emissions, you must also keep the records required under appendix A and/or appendix B to Subpart UUUUU. [40 CFR § 63.10032(a)]

(1) A copy of each notification and report that you submitted to comply with Subpart UUUUU, including all documentation supporting any Initial Notification or Notification of Compliance Status or semiannual compliance report that you submitted, according to the requirements in 40 CFR § 63.10(b)(2)(xiv).

(2) Records of performance stack tests, fuel analyses, or other compliance demonstrations and performance evaluations, as required in 40 CFR § 63.10(b)(2)(viii).

l. For each CEMS, you must keep records according to the following: [40 CFR § 63.10032(b)]

(1) Records described in 40 CFR § 63.10(b)(2)(vi) through (xi).

(2) Previous (i.e., superseded) versions of the performance evaluation plan as required in 40 CFR § 63.8(d)(3).


(3) Request for alternatives to relative accuracy test for CEMS as required in 40 CFR § 63.8(f)(6)(i).

(4) Records of the date and time that each deviation started and stopped, and whether the deviation occurred during a period of startup, shutdown, or malfunction or during another period.

m. You must keep the records required in Table 7 to Subpart UUUUU including records of all monitoring data to show continuous compliance with each emission limit and operating limit that applies to you. [40 CFR § 63.10032(c)]

n. For each EGU subject to an emission limit, you must also keep the records specified below: [40 CFR § 63.10032(d)]

(1) You must keep records of monthly fuel use by each EGU, including the type(s) of fuel and amount(s) used.

(2) If you combust non-hazardous secondary materials that have been determined not to be solid waste pursuant to 40 CFR 241.3(b)(1), you must keep a record which documents how the secondary material meets each of the legitimacy criteria. If you combust a fuel that has been processed from a discarded non-hazardous secondary material pursuant to 40 CFR 241.3(b)(2), you must keep records as to how the operations that produced the fuel satisfies the definition of processing in 40 CFR 241.2. If the fuel received a non-waste determination pursuant to the petition process submitted under 40 CFR 241.3(c), you must keep a record which documents how the fuel satisfies the requirements of the petition process.

(3) For an EGU that qualifies as an LEE under 40 CFR § 63.10005(h), you must keep annual records that document that your emissions in the previous stack test(s) continue to qualify the unit for LEE status for an applicable pollutant, and document that there was no change in source operations including fuel composition and operation of air pollution control equipment that would cause emissions of the pollutant to increase within the past year.

o. If you elect to average emissions consistent with 40 CFR § 63.10009, you must additionally keep a copy of the emissions averaging implementation plan required in 40 CFR § 63.10009(g), all calculations required under 40 CFR § 63.10009, including daily records of heat input or steam generation, as applicable, and monitoring records consistent with 40 CFR § 63.10022. [40 CFR § 63.10032(e)]

p. You must keep the following records for each startup and/or shutdown: [40 CFR § 63.10032(f)]

(1) Records of the occurrence and duration of each startup or shutdown;

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

(3) Records of the determination of the maximum hourly clean fuel heat input and of the hourly clean fuel heat input for each EGU; and

(4) Records of the information required in 40 CFR § 63.10020(e).

q. You must keep records of the occurrence and duration of each malfunction of an operation (i.e., process equipment) or the air pollution control and monitoring equipment. [40 CFR § 63.10032(g)]


r. You must keep records of actions taken during periods of malfunction to minimize emissions in accordance with 40 CFR § 63.10000(b), including corrective actions to restore malfunctioning process and air pollution control and monitoring equipment to its normal or usual manner of operation. [40 CFR § 63.10032(h)]

s. You must keep records of the type(s) and amount(s) of fuel used during each startup or shutdown. [40 CFR § 63.10032(i)]

t. Your records must be in a form suitable and readily available for expeditious review, according to 40 CFR § 63.10(b)(1). [40 CFR § 63.10033(a)]

u. As specified in 40 CFR § 63.10(b)(1), you must keep each record for 5 years following the date of each occurrence, measurement, maintenance, corrective action, report, or record. [40 CFR § 63.10033(b)]

v. You must keep each record on site for at least 2 years after the date of each occurrence, measurement, maintenance, corrective action, report, or record, according to 40 CFR § 63.10(b)(1). You can keep the records off site for the remaining 3 years. [40 CFR § 63.10033(c)]

TABLES TO SUBPART UUUUU OF PART 63

Table 3 to Subpart UUUUU of Part 63—Work Practice Standards

As stated in §40 CFR § 63.9991, you must comply with the following applicable work practice standards:

If your EGU is . . . You must meet the following . . .

1. An existing EGU Conduct a tune-up of the EGU burner and combustion controls at least each 36 calendar months, or each 48 calendar months if neural network combustion optimization software is employed, as specified in 40 CFR § 63.10021(e).

3. A coal-fired, liquid oil-fired, or solid 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 for the purpose of producing electricity, or the firing of fuel in a boiler after a shutdown event for any purpose. Startup ends when any of the steam from the boiler is used to generate electricity for sale over the grid or for any other purpose (including on site use). For startup of a unit, you must use clean fuels as defined in 40 CFR § 63.10042 for ignition. Once you convert to firing coal, residual oil, or solid oil-derived fuel, you must engage all of the applicable control technologies except dry scrubber and SCR. You must start your dry scrubber and SCR systems, if present, appropriately to comply with relevant standards applicable during normal operation. You must comply with all applicable emissions limits at all times except for periods that meet the applicable definitions of startup and shutdown in this subpart. You must keep records during startup periods. You must provide reports concerning activities and startup periods, as specified in 40 CFR § 63.10011(g) and 40 CFR § 63.10021(h) and (i). For startup of an EGU, you must use one or a combination of the clean fuels defined in 40 CFR § 63.10042 to the maximum extent possible throughout the startup period. You must have sufficient clean fuel capacity to engage and operate your PM control device within one hour of adding coal, residual oil, or solid oil-derived fuel to the unit. You must meet the startup period work practice requirements as identified in 40 CFR § 63.10020(e).


Once you start firing coal, residual oil, or solid oil-derived fuel, you must vent emissions to the main stack(s). You must comply with the applicable emission limits within 4 hours of start of electricity generation. You must engage and operate your particulate matter control(s) within 1 hour of first firing of coal, residual oil, or solid oil-derived fuel. You must start all other applicable control devices as expeditiously as possible, considering safety and manufacturer/supplier recommendations, but, in any case, when necessary to comply with other standards made applicable to the EGU by a permit limit or a rule other than this Subpart that require operation of the control devices. Relative to the syngas not fired in the combustion turbine of an IGCC EGU during startup, you must either: (1) flare the syngas, or (2) route the syngas to duct burners, which may need to be installed, and route the flue gas from the duct burners to the heat recovery steam generator. If you choose to use just one set of sorbent traps to demonstrate compliance with Hg emission limits, you must comply with all applicable Hg emission limits at all times; otherwise, you must comply with all applicable emission limits at all times except for startup or shutdown periods conforming to this practice. You must collect monitoring data during startup periods, as specified in 40 CFR § 63.10020(a) and (e). You must keep records during startup periods, as provided in 40 CFR §§ 63.10032 and 63.10021(h). Any fraction of an hour in which startup occurs constitutes a full hour of startup. You must provide reports concerning activities and startup periods, as specified in 40 CFR §§ 63.10011(g), 63.10021(i), and 63.10031.

4. A coal-fired, liquid oil-fired, or solid 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 control devices and continue to operate those control devices after the cessation of coal, residual oil, or solid oil-derived fuel being fed into the EGU and for as long as possible thereafter considering operational and safety concerns. In any case, you must operate your controls when necessary to comply with other standards made applicable to the EGU by a permit limit or a rule other than this Subpart and that require operation of the control devices. If, in addition to the fuel used prior to initiation of shutdown, another fuel must be used to support the shutdown process, that additional fuel must be one or a combination of the clean fuels defined in 40 CFR § 63.10042 and must be used to the maximum extent possible. Relative to the syngas not fired in the combustion turbine of an IGCC EGU during shutdown, you must either: (1) flare the syngas, or (2) route the syngas to duct burners, which may need to be installed, and route the flue gas from the duct burners to the heat recovery steam generator. You must comply with all applicable emission limits at all times except during startup periods and shutdown periods at which time you must meet this work practice. You must collect monitoring data during shutdown periods, as specified in 40 CFR § 63.10020(a). You must keep records during shutdown periods, as


provided in 40 CFR §§ 63.10032 and 63.10021(h). Any fraction of an hour in which shutdown occurs constitutes a full hour of shutdown. You must provide reports concerning activities and shutdown periods, as specified in 40 CFR §§ 63.10011(g), 63.10021(i), and 63.10031.

Table 5 to Subpart UUUUU of Part 63—Performance Testing Requirements

As stated in 40 CFR § 63.10007, you must comply with the following requirements for performance testing for existing, new or reconstructed affected sources:1

To conduct a performance test for the following pollutant . . . Using . . .

You must perform the following activities, as applicable to your input- or output-based emission limit . . . Using2 . . .

1. Filterable Particulate matter (PM)

PM CEMS a. Install, certify, operate, and

maintain the PM CEMS

Performance Specification 11 at

Appendix B to part 60 of this chapter

and Procedure 2 at Appendix F to

Part 60 of this chapter.

b. Install, certify, operate, and

maintain the diluent gas, flow

rate, and/or moisture

monitoring systems

Part 75 of this chapter and 40 CFR §§

63.10010(a), (b), (c), and (d).

c. Convert hourly emissions

concentrations to 30 boiler

operating day rolling average

lb/MMBtu or lb/MWh emissions

rates

Method 19 F-factor methodology at

Appendix A-7 to part 60 of this

chapter, or calculate using mass

emissions rate and electrical output

data (see 40 CFR § 63.10007(e)).

5. Sulfur dioxide (SO2) SO2 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)).

3Incorporated 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:


If you use one of the following to meet applicable emissions limits, operating limits, or work practice standards . . . You demonstrate continuous compliance by . . .

1. CEMS to measure filterable PM, SO2, HCl, HF, or Hg emissions, or using a sorbent trap monitoring system to measure Hg

Calculating the 30- (or 90-) boiler operating day rolling arithmetic average emissions rate in units of the applicable emissions standard basis at the end of each boiler operating day using all of the quality assured hourly average CEMS or sorbent trap data for the previous 30- (or 90-) boiler operating days, excluding data recorded during periods of startup or shutdown.

4. Quarterly performance testing for coal-fired, solid oil derived fired, or liquid oil-fired EGUs to measure compliance with one or more non-PM (or its alternative emission limits) applicable emissions limit in Table 1 or 2, or PM (or its alternative emission limits) applicable emissions limit in Table 2

Calculating the results of the testing in units of the applicable emissions standard.

5. Conducting periodic performance tune-ups of your EGU(s)

Conducting periodic performance tune-ups of your EGU(s), as specified in 40 CFR § 63.10021(e).

6. Work practice standards for coal-fired, liquid oil-fired, or solid oil-derived fuel-fired EGUs during startup

Operating in accordance with Table 3.

7. Work practice standards for coal-fired, liquid oil-fired, or solid oil-derived fuel-fired EGUs during shutdown

Operating in accordance with Table 3.

Table 8 to Subpart UUUUU of Part 63—Reporting Requirements

As stated in 40 CFR § 63.10031, you must comply with the following requirements for reports:

You must submit a . . . The report must contain . . .

You must submit the report . . .

1. Compliance report

a. Information required in 40 CFR § 63.10031(c)(1) through (4); and b. If there are no deviations from any emission limitation (emission limit and operating limit) that applies to you and there are no deviations from the requirements for work practice standards in Table 3 to Subpart UUUUU that apply to you, a statement that there were no deviations from the emission limitations and work practice standards during the reporting period. If there were no periods during which the CMSs, including continuous emissions monitoring system, and operating parameter monitoring systems, were out-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 during the reporting period; and

Semiannually according to the requirements in 40 CFR § 63.10031(b).

c. If you have a deviation from any emission limitation (emission limit and operating limit) or work practice standard during the reporting period, the report must contain the information in 40 CFR § 63.10031(d). If there were periods during which the CMSs, including continuous emissions monitoring systems and continuous parameter monitoring systems, were out-of-control, as specified in


40 CFR § 63.8(c)(7), the report must contain the information in 40 CFR § 63.10031(e)

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