TH E NAVAJO NATION
RUSSELL BEGAYE PRES I DE NT
JONATHAN NEZ VICE PRESIDENT
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 #:
NN-OP-15-06
FACILITY NAME:
NAVAJO GENERATING STATION
LOCATION:
PAGE
COUNTY:
COCONINO
STATE:
AZ
ISSUE DATE:
XX/XX/2015
EXPIRATION DATE:
XX/XX/2020
AFS PLANT ID: PERMITTING AUTHORITY:
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
Abbreviations and Acronyms
Administrator
AR
ARP
BART
CAA
CEMS
CFR
COMS
DC
ESP
FGD
gal
HAP
hr
lb
LNB/SOFA
MACT
MVAC
Mg
MMBtu
MW
mo
NESHAP
NMHC
NNEPA
NNOPR
NOX
NSPS
NSR
PM
PM-10
ppm
PSD
PTE
QIP
RHR
RMP
SNAP
SO2
US EPA
VCA
VOC
Administrator of the U.S. EPA
Acid Rain
Acid Rain Program
Best Available Retrofit Technology
Clean Air Act [42 U.S.C. Section 7401 et seq.]
Continuous Emission Monitoring System
Code of Federal Regulations
Continuous Opacity Monitoring System
Dust Collector
Electro Static Precipitator
Flue Gas Desulfurization
gallon
Hazardous Air Pollutant
hour
pound
Low-NOX Burner (LNB) and Separated Overfire Air (SOFA) system
Maximum Achievable Control Technology
Motor Vehicle Air Conditioner
megagram
million British Thermal Units
Megawatts
month
National Emission Standards for Hazardous Air Pollutants
Nonmethane Hydrocarbons
Navajo Nation Environmental Protection Agency
Navajo Nation Operating Permit Regulations
Nitrogen Oxides
New Source Performance Standards
New Source Review
Particulate Matter
Particulate matter less than 10 microns in diameter
parts per million
Prevention of Significant Deterioration
Potential to Emit
Quality Improvement Plan
Regional Haze Rule
Risk Management Plan
Significant New Alternatives Program
Sulfur Dioxide
United States Environmental Protection Agency
Voluntary Compliance Agreement
Volatile Organic Compounds
Page 2 of 62
TABLE OF CONTENTS
Cover Page
Abbreviations and Acronyms
I. Source Identification
II. Requirements for Specific Units
A. Federal Implementation Plan Requirements
B. PSD Permit Requirements
C. Acid Rain Requirements
D. Visibility Federal Implementation Plan Requirements
E. NSPS General Provisions
F. NSPS for Nonmetallic Mineral Processing Plants, 40 CFR Part 60, Subpart OOO
Requirements
G. Monitoring and Testing Requirements to Comply with NSPS for Nonmetallic Mineral
Processing Plants, 40 CFR Part 60, Subpart OOO
H. NSPS for Stationary Compression Ignition Internal Combustion Engines, 40 CFR
Part 60, Subpart IIII Requirements
I. NESHAP General Provisions
J. NESHAP for Coal- and Oil-Fired Electric Utility Steam Generating Units, 40 CFR
Part 63, Subpart UUUUU Requirements
K. NESHAP for Industrial, Commercial, and Institutional Boilers and Process Heaters,
40 CFR Part 63, Subpart DDDDD Requirements
L. NESHAP for Stationary Reciprocating Internal Combustion Engines, 40 CFR Part 63,
Subpart ZZZZ Requirements
M. PM CEM Requirements
N. CAM Requirements
O. Requirements for Reagent Handling Systems
P. Operational Flexibility
III. Facility-Wide or Generic Permit Conditions
A. Testing Requirements
B. Recordkeeping Requirements
C. Reporting Requirements
D. Protection of Stratospheric Ozone
E. Asbestos from Demolition and Renovation
F. Compliance Schedule
IV. Title V Administrative Requirements
A. Fee Payment
B. Blanket Compliance Statement
C. Compliance Certifications
D. Duty to Provide and Supplement Information
E. Submissions
F. Severability Clause
G. Permit Actions
Page 3 of 62
H. Administrative Permit Amendments
I. Minor Permit Modifications
J. Group Processing of Minor Permit Amendments
K. Significant Modifications
L. Reopening for Cause
M. Property Rights
N. Inspection and Entry
O. Emergency Provisions
P. Transfer of Ownership or Operation
Q. Off Permit Changes
R. Permit Expiration and Renewal
S. Additional Permit Conditions
T. Part 71 Permit Enforcement
Attachment A – Dust Control Plan
Attachment B – Phase II Acid Rain Permit Renewal
Attachment C – NESHAP for Coal- and Oil-Fired Electric Utility Steam Generating Units, 40
CFR Part 63, Subpart UUUUU - Compliance, Monitoring, Testing,
Notification, Recordkeeping, and Reporting Requirements
Page 4 of 62
I. Source Identification

Managing Participant Name:
Salt River Project Agricultural Improvement
and Power District (SRP)*

Managing Participant Mailing Address:
P.O. Box 52025, PAB 352
Phoenix, Arizona 85072-2025
*Note: This facility is co-owned by 6 entities. SRP is listed as the managing participant in
this permit since it acts as the facility operator and has accepted the responsibility to
obtain environmental permits for Navajo Generating Station, including an Acid Rain
permit and Part 71 Permit. In addition to SRP, the other 5 co-owners of this facility are:
1.
2.
3.
4.
5.













U.S. Bureau of Reclamation (USBR)
Los Angeles Department of Water and Power (LADWP)
Arizona Public Service Company (APS)
Nevada Power Company (NPC)
Tucson Electric Power (TEP)
Plant Name:
Plant Location:
Navajo Generating Station
5 miles east of Page, AZ off U.S. Highway 98
Page, Arizona
County:
Coconino, Arizona
EPA Region:
9
Reservation:
Navajo Nation
Tribe:
Navajo
Company Contact:
Paul Ostapuk
Phone: (928) 645-6577
Barbara Cenalmor
Phone: (602) 236-2322
Responsible Official:
Robert K. Talbot
Phone: (928) 645-6217
EPA Contact:
Geoffrey Glass
Phone: (415) 972-3498
Tribal Contacts:
Eugenia Quintana
Phone: (928) 871-7800
Tennille Begay
Phone: (928) 729-4248
SIC Code:
4911
AFS Plant Identification Number: 04-005-N0423
Description of Process: The facility is 2,250 Net Megawatt coal-fired power plant.
Page 5 of 62

Significant Emission Units:
Unit ID/
Stack ID
U1/
Stack S1
U2/
Stack S2
U3/
Stack S3
AUX A
AUX B
CT1
L1 - L12
BC-1 through
BC-4
BC-4A
BFD-5A,
BC-5
BC-6
BC-6A through
BC-6C
BC-7
YSB-1
BC-8A,
BC-8B
BC-8AS,
BC-8BS
PSB-1
BC-9A,
BC-9B
BC-10A,
BC-10B
CC-1A through
CC-9A; CC-1B
through CC-9B
Silos 1A through
1G
Silos 2A through
2G
Silos 3A through
3G
Maximum
Capacity
Unit Description
One (1) pulverized coal-fired boiler,
using No. 2 fuel oil for ignition fuel. Stack S1 is
7,410 MBtu/hr;
equipped with SO2, NOX, CO, and PM CEMS
750 Net MW
and a COMS.
One (1) pulverized coal-fired boiler,
using No. 2 fuel oil for ignition fuel. Stack S1 is
7,410 MBtu/hr;
equipped with SO2, NOX, CO, and PM CEMS
750 Net MW
and a COMS.
One (1) pulverized coal-fired boiler,
using No. 2 fuel oil for ignition fuel. Stack S1 is
7,410 MBtu/hr;
equipped with SO2, NOX, CO, and PM CEMS
750 Net MW
and a COMS.
One (1) auxiliary boiler;
308 MMBtu/hr
using No. 2 fuel oil as fuel
One (1) auxiliary boiler;
308 MMBtu/hr
using No. 2 fuel oil as fuel
Coal Handling Operations
One (1) railcar unloading operation
10,000 tons/hr
2,400 tons/hr
Twelve (12) hopper feeders
(total)
1,800 tons/hr
Four (4) conveyors to the yard surge bin
(each)
One (1) conveyor to the batch weight system
100 tons/hr
1,800 tons/hr
Two (2) reclaim conveyors
(each)
One (1) conveyor to the yard surge bin
1,500 tons/hr
1,800 tons/hr
Three (3) conveyors to the stacker/reclaimer
(each)
One (1) conveyor to the emergency reclaim
1,500 tons/hr
hopper
One (1) yard surge bin
1,800 tons/hr
1,500 tons/hr
Two (2) conveyors to plant surge bin
(each)
1,500 tons/hr
Two (2) screens
(each)
One (1) plant surge bin
3,000 tons/hr
Two (2) conveyors to the coal silos for boilers
1,500 tons/hr
U1 and U2
(each)
Two (2) conveyors to the coal silos for boiler
1,500 tons/hr
U3
(each)
Three (3) enclosed cascading conveying systems
1,500 tons/hr
to the coal storage silos for boilers U1, U2, and
(each)
U3
3,000 tons/hr
Seven (7) storage silos for boiler U1
(each)
3,000 tons/hr
Seven (7) storage silos for boiler U2
(each)
3,000 tons/hr
Seven (7) storage silos for boiler U3
(each)
Page 6 of 62
Commenced
Construction
Date
1970
1970
1970
Control Method
ESP1; FGD system
SCBR1 (1999);
LNB/SOFA*(2011);
Sorbent Injection (2015)
ESP2; FGD system
SCBR2 (1998);
LNB/SOFA*(2010);
Sorbent Injection (2015)
ESP3; FGD system
SCBR3 (1997);
LNB/SOFA*(2009);
Sorbent Injection (2015)
1970
N/A
1970
N/A
1970
wet suppression
1970
wet suppression
1970
DC-8
1970
DC-8
1970
DC-8
1970
DC-8
wet suppression/
enclosure
1970
1970
wet suppression
1970
DC-8
1970
DC-8
1970
DC-8
1970
DC-5
1970
DC-5
1970
DC-5
1970
DC-1 through DC-4,
DC-6, and DC-7
1970
1970
1970
DC-1, DC-2, and
baghouse PR-1.
DC-3, DC-4, and
baghouse PR-2.
DC-6, DC-7, and
baghouse PR-3.
Unit ID/
Stack ID
CS
Unloading Bay
A and B
O-LSH-HOP-A
O-LSH-HOP-B
O-LSH-FDR-A
O-LSH-FDR-B
O-LSH-CNV-A
O-LSH-CNV-B
O-LSH-SILO-A
and B
O-LSP-FDR-A
and B
O-LSP-CNV-A
and B
O-LSP-MILL-A
and B
LS
Silo 1
Silo 2
Silo 1 and 2
Loading
DWB-A through
DWB-F
3,300 tons/hr
1970
(total)
Limestone Handling System Associated with the FGD Systems
38 tons/hr
Two (2) truck unloading operations
1997
(each)
One (1) limestone unloading hopper
300 tons/hr
1997
One (1) limestone unloading hopper
300 tons/hr
1997
One (1) conveyor
300 tons/hr
1997
One (1) conveyor
300 tons/hr
1997
One (1) conveyor
300 tons/hr
1997
One (1) conveyor
300 tons/hr
1997
300 tons/hr
Two (2) limestone storage silos
1997
(each)
Two (2) enclosed feeders to the slurry
36 tons/hr
1997
preparation system
(each)
5 tons/hr
Two (2) enclosed cleanout conveyors
1997
(each)
36 tons/hr
Two (2) ball mills
1997
(each)
600 tons/hr
Limestone storage piles
1997
(total)
Fly Ash Handling System
One (1) fly ash bin for boilers U1 and U2
46 tons/hr
1970
One (1) fly ash bin for boiler U3
46 tons/hr
1970
Two (2) partially enclosed fly ash truck loading
38 tons/hr
1970
operations
(each)
Six (6) bottom ash truck loading operations.
46 tons/hr
1970
The bottom ash is processed in a wet form
(each)
Soda Ash/Lime Handling Systems
Four (4) soda ash storage bins
LB-1 and LB-2
Two (2) lime storage bins
Fugitive-CaBr2
TR
Commenced
Construction
Date
Outdoor coal storage piles
SAB-1A, SAB2A, SAB-1B,
SAB-2B
PAC Silo A
PAC Silo B
Fugitive-PAC
Maximum
Capacity
Unit Description
0.4 tons/hr
(each)
0.57 tons/hr
(each)
Reagent Handing Systems
Power active carbon (PAC) storage silo
40 tons
PAC storage silo
40 tons
Truck traffic on unpaved roads for PAC delivery
30 VMT/yr**
Truck traffic on unpaved roads for Calcium
365 VMT/yr**
Bromide delivery
Miscellaneous Operations
813,000 gal/min
Six (6) cooling towers
(total)
Fugitive emissions from unpaved roads
N/A
Note: (*) LNB/SOFA = Low-NOX burner (LNB) and Separated Overfire Air (SOFA) system.
(**) VMT = vehicle miles traveled.
Page 7 of 62
Control Method
wet suppression
N/A
DC-9
DC-10
DC-9
DC-10
DC-9
DC-10
DC-11
N/A
N/A
N/A
wet suppression
DC-S1/2
DC-S3
DC-S1/2 and DC-S3
wet suppression
1970
dust collector BH-6
1970
dust collector BH-7
2015
2015
2015
integral baghouse
integral baghouse
water spray
2015
water spray
1970
N/A
1970
wet suppression
II. Requirements for Specific Units
II.A. Federal Implementation Plan Requirements. The following requirements apply to
coal-fired boilers U1, U2, and U3, coal and ash handling equipment, and the two
auxiliary steam boilers at Navajo Generating Station. [40 CFR § 49.5513]
1.
Definitions. The following definitions apply to Section II.A of this permit
[40 CFR § 49.5513(c)]:
a.
Absorber upset transition period means the 24-hour period following an
upset of an SO2 absorber module which resulted in the absorber being
taken out of service.
b.
Affirmative defense means, in the context of an enforcement proceeding, a
response or defense put forward by a defendant, regarding which the
defendant has the burden of proof, and the merits of which are
independently and objectively evaluated in a judicial or administrative
proceeding. 40 CFR § 49.5513provides an affirmative defense to
actions for penalties brought for excess emissions that arise
during certain malfunction episodes.
c.
Malfunction means any sudden and unavoidable failure of air pollution
control equipment or process equipment or of a process to operate in a
normal or usual manner. Failures that are caused entirely or in part by poor
maintenance, careless operation, or any other preventable upset
condition or preventable equipment breakdown shall not be
considered malfunctions. An affirmative defense is not available if
during the period of excess emissions, there was an exceedance of the
relevant ambient air quality standard that could be attributed to the
emitting source.
d.
Plant-wide means a weighted average of particulate matter and SO2
emissions for boilers U1, U2, and U3 based on the heat input to each
unit as determined by 40 CFR Part 75.
e.
Point source means any crusher, any conveyor belt transfer point, any
pneumatic material transferring, any baghouse or other control devices
used to capture dust emissions from loading and unloading, and any other
stationary point of dust that may be observed in conformance with
Method 9 of Appendix A-4 of 40 CFR Part 60 (excluding stockpiles).
f.
Regional Administrator means the Regional Administrator of the
Environmental Protection Agency, Region 9, or his/her authorized
representative.
g.
Startup means the period from the start of fires in the boiler with fuel oil,
Page 8 of 62
to the time when the electrostatic precipitator is sufficiently heated such
that the temperature of the air preheater inlet reaches 400 degrees
Fahrenheit and when a unit reaches 300 MW net load. Proper startup
procedures shall include energizing the electrostatic precipitator prior to
the combustion of coal in the boiler. 40 CFR § 49.5513 provides an
affirmative defense to actions for penalties brought for excess emissions
that arise during startup episodes. An affirmative defense is not available
if during the period of excess emissions, there was an exceedance of the
relevant ambient air quality standard that could be attributed to the
emitting source.
2.
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.
Emissions Limitations and Control Measures [40 CFR § 49.5513(d)]:
a.
Sulfur oxides (SO2). The permittee shall not discharge or cause the
discharge of sulfur oxides into the atmosphere from boilers U1, U2 and
U3in excess of 1.0 pound per million British thermal units
(lb/MMBtu) averaged over any three (3) hour period, on a plant-wide
basis.
b.
Particulate matter (PM). The permittee shall not discharge or cause the
discharge of particulate matter into the atmosphere in excess of 0.060
lb/MMBtu, on a plant-wide basis, as averaged from at least three sampling
runs per stack, each at a minimum of 60 minutes in duration, each
collecting a minimum sample of 30 dry standard cubic feet.
c.
Dust. The permittee shall operate and maintain the existing dust suppression
methods for controlling dust from the coal handling and storage
facilities. A dust control plan was submitted by the permittee on June
4, 2010 in accordance with 40 CFR § 49.5513(d)(3). A revised plan
was submitted on February 2, 2015 and is attached as Attachment A
to this permit. The permittee shall not emit dust with an opacity greater
than 20% from any crusher, grinding mill, screening operation, belt conveyor,
truck loading or unloading operation, or railcar unloading station, as
Page 9 of 62
determined using 40 CFR Part 60, Appendix A-4, Method 9.
d.
3.
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.
Testing and Monitoring [40 CFR § 49.5513(e)]:
a.
The permittee shall maintain and operate Continuous Emissions
Monitoring Systems (CEMS) for NOX and SO2 and Continuous Opacity
Monitoring Systems (COMS) on boilers U1, U2, and U3 in accordance
with 40 CFR §§ 60.8 and 60.13(e), (f), and (h), and Appendix B of 40
CFR Part 60. The permittee shall comply with the quality assurance
procedures for CEMS and COMS found in 40 CFR part 75.
b.
The permittee shall conduct annual mass emissions tests for particulate
matter on boilers U1, U2, and U3, operating at rated capacity, using coal
that is representative of that normally used. The tests shall be
conducted using the appropriate test methods in 40 CFR Part 60,
Appendix A.
c.
During any calendar year in which an auxiliary boiler is operated for 720
hours or more, and at other times as requested by the Administrator, the
permittee shall conduct mass emissions tests for sulfur dioxide, nitrogen
oxides and particulate matter on the auxiliary steam boilers, operating at
rated capacity, using oil that is representative of that normally used. The
tests shall be conducted using the appropriate test methods in 40 CFR Part
60, Appendix A. For particulate matter, testing shall consist of three test
runs. Each test run shall be at least sixty (60) minutes in duration and shall
collect a minimum volume of thirty (30) dry standard cubic feet.
d.
The permittee shall maintain two sets of opacity filters for each type of
COMS, one set to be used as calibration standards and one set to be used
as audit standards. At least one set of filters shall be on site at all times.
e.
All emissions testing and monitor evaluation required pursuant to 40
CFR § 49.5513(e) shall be conducted in accordance with the appropriate
method found in 40 CFR Part 60, Appendices A and B.
f.
The permittee shall install, maintain and operate ambient monitors at Glen
Canyon Dam for particulate matter (PM2.5 and PM10), nitrogen dioxide,
sulfur dioxide, and ozone. Operation, calibration and maintenance of the
monitors shall be performed in accordance with 40 CFR Part 58,
Page 10 of 62
manufacturer’s specification, and “Quality Assurance Handbook for Air
Pollution Measurements Systems”, Volume II, U.S. EPA as applicable to
single station monitors. Data obtained from the monitors shall be reported
annually to the Regional Administrator. All particulate matter samplers
shall operate at least once every six days, coinciding with the national
particulate sampling schedule.
4.
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.
–
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
Page 11 of 62
the applicable emissions limitation and the operating data and
calculations used in determining the magnitude of the excess
emissions;
c.
d.
(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.
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.
Submit quarterly excess emissions reports for sulfur dioxide and
opacity as recorded by CEMS and COMS together with a CEMS data
assessment report to the Regional Administrator no later than 30 days
after each calendar quarter. The permittee shall complete the excess
emissions reports according to the procedures in 40 CFR § 60.7(c) and
(d) and include the Cylinder Gas Audit. Excess opacity due to
condensed water vapor in the stack does not constitute a reportable
exceedance; however, the length of time during which water vapor
interfered with COMs readings should be summarized in the 40 CFR § §
Page 12 of 62
60.7 (c) report.
5.
Compliance Certifications [40 CFR § 49.5513(g)]:
Notwithstanding any other provision in this permit, the permittee may use any
credible evidence or information relevant to whether a source would have
been in compliance with applicable requirements if the appropriate
performance or compliance test had been performed, for the purpose of
submitting compliance certifications.
6.
Equipment Operations [40 CFR § 49.5513(h)]:
The permittee shall operate all equipment or systems needed to comply with this
section in accordance with 40 CFR § 60.11(d) and consistent with good
engineering practices to keep emissions at or below the emissions limitations in
this section, and following outages of any control equipment or systems the
control equipment or system will be returned to full operation as expeditiously as
practicable.
7.
Enforcement [40 CFR § 49.5513(i)]:
a.
Notwithstanding any other provision in this permit, any credible evidence
or information relevant to whether a source would have been in
compliance with applicable requirements if the appropriate
performance or compliance test had been performed can be used to
establish whether or not a person has violated or is in violation of any
applicable standard.
b.
c.
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.
Emissions in excess of the level of the applicable emission limit or
requirement that occur due to a malfunction shall constitute a violation of
the applicable emission limit. However, it shall be an affirmative
defense in an enforcement action seeking penalties if the permittee has
met with all of the following conditions:
Page 13 of 62
8.
(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.
Regional Haze Best Available Retrofit Technology (BART)
Requirements [40 CFR § 49.5513(j)]:
a.
Total cumulative NOX emissions from boilers U1, U2, and U3, from
January 1, 2009 to December 31, 2044, may not exceed the 2009-2044
NOX Cap (494,899 tons). The permittee must implement the applicable
operating scenario under 40 CFR § 49.5513(j)(3)(i) to ensure NOX
emission reductions sufficient to maintain total cumulative NOX
emissions from U1 through U3 below the 2009-2044 NOX Cap. [40
CFR § 49.5513(j)(3)]
b.
No later than December 1, 2019, the permittee must notify U.S. EPA of
the applicable Alternative for ensuring compliance with the 2009-2044
NOx Cap. [40 CFR § 49.5513(j)(4)(i)]
c.
Beginning in 2015, and annually thereafter until the earlier of December
22, 2044 or the date on which the permittee ceases conventional coalfired electricity generation by all coal-fired Units at NGS, the permittee
must report to U.S. EPA the annual heat input and the annual emissions
Page 14 of 62
of sulfur dioxide, carbon dioxide, and NOX from the previous full
calendar year. In addition, the permittee must also report total cumulative
emissions of NOX from NGS to assure compliance with the 2009-2044
NOX Cap and the 2009-2029 NOX Cap (416,865 tons), if applicable. The
permittee must make this report available to the public, either through a
link on its website or directly on its website. The report must be made
available within 30 days of the submittal deadline associated with the
annual emission inventory required by this permit. [40 CFR §
49.5513(j)(4)(ii)]
d.
No later than December 31, 2020, the permittee must submit an
application to revise its existing Part 71 Operating Permit to incorporate
the requirements and emission limits of the applicable Alternative to
BART under 40 CFR § 49.5513(j)(3) and the NOx emission limits
specified in § 49.5513(j)(4)(iii) . The Part 71 operating permit for NGS
must incorporate practically enforceable limits for NOX of 0.24
lb/MMBtu, on a 30-day rolling average basis, for each unit equipped with
LNB/SOFA, and 0.07 lb/MMBtu, on a rolling average basis of 30 boiler
operating days, for each unit equipped with SCR, as federally enforceable
permit conditions. [40 CFR § 49.5513(j)(4)(iii)]
e.
If Alternative B operating scenario, as defined in 40 CFR §
49.5513(j)(3)(i)(D), is selected, the permittee shall submit annual
Emission Reduction Plans to the EPA as specified in 40 CFR §
49.5513(j)(4)(iv)(A-C). [40 CFR § 49.5513(j)(4)(iv)]
f.
The permittee shall comply with the following requirements for NOX
CEMS [40 CFR § 49.5513(j)(5)]:
(i)
At all times, the permittee must maintain, calibrate, and operate a
CEMS, in full compliance with the requirements found at 40 CFR
part 75, to accurately measure NOX, diluent, and stack gas
volumetric flow rate from each unit. All hourly valid data will be
used to determine compliance with the emission limitations for
NOX in Condition II.A.8.a for each unit. If the CEMs data is not
valid, that CEMs data shall be treated as missing data and not used
to calculate the emission average. CEMs data does not need to be
bias adjusted as defined in 40 CFR part 75. Each required CEMS
must obtain valid data for at least 90 percent of the unit operating
hours, on an annual basis.
(ii)
The permittee shall comply with the quality assurance procedures
for CEMS found in 40 CFR part 75. In addition to these Part 75
requirements, relative accuracy test audits shall be calculated for
both the NOX pounds per hour measurement and the heat input
measurement. The calculation of NOX pounds per hour and heat
Page 15 of 62
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 coalfired units until the earlier of December 22, 2044 or the date that
conventional coal-fired operation of all units at NGS permanently ceases:
[40 CFR § 49.5513(j)(7)]
(i)
(ii)
(iii)
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.
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.
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 U1U3, 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.
b.
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.
NOx emissions shall not exceed 0.24 lb/MMBtu based on a 30-day rolling
average.
Page 16 of 62
2.
At all times, including periods of startup and shutdown, the permittee shall, to the
extent practicable, maintain and operate the LNB/SOFA system in a manner
consistent with good combustion practices to minimize emissions. [PSD Permit
AZ 08-01A, Condition IX.D]
3.
Continuous Emission Monitoring Systems Requirements: [PSD Permit AZ
08-01A, Condition IX.E]
4.
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.
Recordkeeping and Reporting Requirements [PSD Permit AZ 08-01A,
Condition IX.G]
a.
The permittee shall maintain records of the hours of operation for U1, U2
and U3 on a monthly basis.
b.
The permittee shall maintain records of the amount of fuel used in U1, U2
and U3 on a monthly basis.
c.
The permittee shall maintain all records on site of actual operating data
and emissions calculations for emissions limits required in Condition
II.B.1.
d.
The permittee shall maintain CEMS records that contain the following: the
occurrence and duration of any startup, shutdown or malfunction,
Page 17 of 62
performance testing, evaluations, calibrations, checks, adjustments,
maintenance, duration of any periods during which a continuous
monitoring system or monitoring device is inoperative, and emission
measurements.
e.
The permittee shall maintain records and submit a written report of all
excess emissions to EPA semi-annually. The report is due on the 30th day
following the end of the calendar quarter and shall include the following:
(i)
Time intervals, data and magnitude of the excess emissions, the
nature and cause (if known), corrective actions taken and
preventive measures adopted;
(ii)
Applicable time and date of each period during which the CEMS
was inoperative (monitor down time), except for zero and span
checks, and the nature of system repairs or adjustments; and
(iii)
A negative declaration when no excess emissions occurred or
when the CEMS has not been inoperative, repaired, or adjusted.
f.
Excess emissions shall be defined as any operating day in which the 30day rolling average CO and NOx concentration, as measured by the
CEMS, exceeds the maximum emission limits set forth in Condition
II.B.1.
g.
A period of monitor down time shall be any unit operating hour in which
sufficient data are not obtained to validate the hour for CO, NOx, or O2.
h.
Excess emissions indicated by the CEMS shall be considered violations of
the applicable emission limit.
II.C. Acid Rain Requirements [40 CFR Parts 72-78; Phase II Acid Rain Permit]
The permittee shall comply with the requirements listed in the attached acid rain permit
renewal (see Attachment B).
II.D. Visibility Federal Implementation Plan Requirements [40 CFR § 52.145(d)]
1.
Definitions. The following definitions apply to Condition II.D of this permit [40
CFR § 52.145(d)(1)]:
a.
“Administrator” means the Administrator of EPA or his/her designee.
b.
“Affected Units” means steam-generating units U1, U2 and U3 at the
Navajo Generating Station, all of which are subject to the emission
limitation in Condition II.D.2 of this permit.
Page 18 of 62
c.
“Boiler Operating Day” for each of the boiler units at the Navajo
Generating Station is defined as a 24-hour calendar day (the period of time
between 12:01 a.m. and 12:00 midnight in Page, Arizona) during which
coal is combusted in that unit for the entire 24 hours.
d.
“Unit-Week of Maintenance” means a period of 7 days during which a
fossil fuel-fired steam-generating unit is under repair and no coal is
combusted in the unit.
2.
Emission limitation. The permittee shall not discharge or cause the discharge of
sulfur oxides into the atmosphere in excess of 42 ng/J [0.10 pound per million
British thermal units (lb/MMBtu)] heat input [40 CFR § 52.145(d)(2)].
3.
Compliance determination. Compliance with the emission limit in Condition
II.D.2 of this permit shall be determined daily on a plant-wide rolling annual basis
as follows [40 CFR § 52.145(d)(3)]:
a.
For each boiler operating day at each steam generating unit subject to the
emission limitation in Condition II.D.2 of this permit, the permittee shall
record the unit’s hourly SO2 emissions using the data from the continuous
emission monitoring systems, required in Condition II.D.4 of this permit,
and the daily electric energy generated by the unit (in megawatt-hours) as
measured by the megawatt-hour meter for the unit.
b.
Compute the average daily SO2 emission rate in ng/J (lb/MMBtu)
following the procedures set out in Method 19, Appendix A, 40 CFR Part
60 in effect on October 3, 1991.
c.
For each boiler operating day for each affected unit, calculate the product
of the daily SO2 emission rate (computed according to Condition II.D.3.b
of this permit) and the daily electric energy generated (recorded according
to Condition II.D.3.a of this permit) for each unit.
d.
For each affected unit, identify the previous 365 boiler operating days to
be used in the compliance determination. Except as provided in Condition
II.D.7 of this permit, all of the immediately preceding 365 boiler operating
days will be used for compliance determinations.
e.
Sum, for all affected units, the products of the daily SO2 emission rateelectric energy generated (as calculated according to Condition II.D.3.c of
this permit) for the boiler operating days identified in Condition II.D.3d of
this permit.
Page 19 of 62
f.
Sum, for all affected units, the daily electric energy generated (recorded
according to Condition II.D.3.a of this permit) for the boiler operating
days identified in Condition II.D.3.d of this permit.
g.
Calculate the weighted plant-wide annual average SO2 emission rate by
dividing the sum of the products determined according to Condition
II.D.3.e of this permit by the sum of the electric energy generated
determined according to Condition II.D.3.f of this permit.
h.
The weighted plant-wide annual average SO2 emission rate shall be used
to determine compliance with the emission limitation in Condition II.D.2
of this permit.
4.
Continuous emission monitoring. The permittee shall install, maintain, and
operate continuous emission monitoring systems to determine compliance with
the emission limitation in Condition II.D.2 of this permit as calculated in
Condition II.D.3 of this permit. This equipment shall meet the specifications in
Appendix B of 40 CFR Part 60 in effect on October 3, 1991. The permittee shall
comply with the quality assurance procedures for continuous emission monitoring
systems found in Appendix F of 40 CFR 60 in effect on October 3, 1991 [40 CFR
§ 52.145(d)(4)].
5.
Reporting requirements. For each steam generating unit subject to the emission
limitation in Condition II.D.2 of this permit, the permittee [40 CFR §
52.145(d)(5)]:
6.
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.
Compliance dates. The requirements of Section II.D of this permit shall be
applicable to all units at this facility beginning on August 19, 1999 [40 CFR §
52.145(d)(6)].
Page 20 of 62
7.
Exclusion for catastrophic failure. Any periods of emissions from an affected unit
for which the Administrator finds that the control equipment or system for such
unit is out of service because of catastrophic failure of the control system which
occurred for reasons beyond the control of the permittee and could not have been
prevented by good engineering practices will be excluded from the compliance
determination. Events which are the consequence of lack of appropriate
maintenance or of intentional or negligent conduct or omissions of the permittee
or the control system design, construction, or operating contractors do not
constitute catastrophic failure [40 CFR § 52.145(d)(10)].
8.
Equipment operation. The permittee shall optimally operate all equipment or
systems needed to comply with the requirements of this paragraph consistent with
good engineering practices to keep emissions at or below the emission limitation
in Condition II.D.2 of this permit, and following outages of any control
equipment or system the control equipment or system will be returned to full
operation as expeditiously as practicable [40 CFR § 52.145(d)(11)].
9.
Maintenance scheduling. On March 16 of each year starting in 1993, the permittee
shall prepare and submit to the Administrator a long-term maintenance plan for
the Navajo Generating Station which accommodates the maintenance
requirements for the other generating facilities on the Navajo Generating Station
grid covering the period from March 16 to March 15 of the next year and showing
at least 6 unit-weeks of maintenance for the Navajo Generating Station during the
November 1 to March 15 period, except as provided in Condition II.D.10 of this
permit. This plan shall be developed consistent with the criteria established by the
Western Electric Coordinating Council of the North American Electric Reliability
Corporation to ensure an adequate reserve margin of electric generating capacity.
At the time that a plan is transmitted to the Administrator, the permittee shall
notify the Administrator in writing if less than the full scheduled unit-weeks of
maintenance were conducted for the period covered by the previous plan and shall
furnish a written report stating how that year qualified for one of the exceptions
identified in Condition II.D.10 of this permit [40 CFR § 52.145(d)(12)].
10.
Exceptions for maintenance scheduling. The permittee shall conduct a full 6 unitweeks of maintenance in accordance with the plan required in Condition II.D.9 of
this permit unless the permittee can demonstrate to the satisfaction of the
Administrator that a full 6 unit-weeks of maintenance during the November 1 to
March 15 period should not be required because of the following [40 CFR §
52.145(d)(13)]:
a.
There is no need for 6 unit-weeks of scheduled periodic maintenance in
the year covered by the plan;
Page 21 of 62
11.
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.
If the Administrator determines that a full 6 unit-weeks of maintenance during the
November 1 to March 15 period should not be required, the permittee shall
nevertheless conduct that amount of scheduled maintenance that is not precluded
by the Administrator. Generally, the permittee shall make best efforts to conduct
as much scheduled maintenance as practicable during the November 1 to March
15 period. [40 CFR § 52.145(d)(13)]
II.E. NSPS General Provisions [40 CFR Part 60, Subpart A]
The following requirements apply to the affected facilities in the limestone handling
system in accordance with 40 CFR Part 60, Subparts A and OOO (“Standards of
Performance for Nonmetallic Mineral Processing Plants”) and to the emergency fire
pump (NGS-120A) in accordance with 40 CFR Part 60, Subparts A and IIII (“Standards
of Performance for Stationary Compression Ignition Internal Combustion Engines”):
1.
All requests, reports, applications, submittals, and other communications to the
NNEPA pursuant to 40 CFR Part 60 shall be submitted in duplicate to the EPA
Region 9 office at the following address [40 CFR § 60.4(a)]:
Director, Air Division (Attn: AIR-1)
EPA Region IX
75 Hawthorne Street
San Francisco, CA 94105
2.
The permittee shall maintain records of the occurrence and duration of any
startup, shutdown, or malfunction in the operation of an affected facility; any
malfunction of the air pollution control equipment; or any periods during which a
continuous monitoring system or monitoring device is inoperative [40 CFR §
60.7(b)].
3.
The availability to the public of information provided to, or otherwise obtained
by, the EPA Administrator under this permit shall be governed by 40 CFR § 2.
(Information submitted voluntarily to the Administrator for the purposes of
Page 22 of 62
compliance with 40 CFR §§ 60.5 and 60.6 is governed by 40 CFR §§ 2.201
through § 2.213 and not by 40 CFR § 2.301.) [40 CFR § 60.9].
6.
The opacity standards set forth in 40 CFR Part 60 shall apply at all times except
during periods of startup, shutdown, malfunction, and as otherwise provided [40
CFR § 60.11(c)].
7.
At all times, including periods of startup, shutdown, and malfunction, the
permittee shall, to the extent practicable, maintain and operate the affected
facilities, including associated air pollution control equipment, in a manner
consistent with good air pollution control practice for minimizing emissions.
Determination of whether acceptable operating and maintenance procedures are
being used will be based on information available to the Administrator which may
include, but is not limited to, monitoring results, opacity observations, review of
operating and maintenance procedures, and inspection of the source [40 CFR §
60.11(d)].
8.
For the purpose of submitting compliance certifications or establishing whether or
not a person has violated or is in violation of any standard in 40 CFR Part 60,
nothing in 40 CFR Part 60 shall preclude the use, including the exclusive use, of
any credible evidence or information, relevant to whether a source would have
been in compliance with applicable requirements if the appropriate performance
or compliance test or procedure had been performed [40 CFR § 60.11(g)].
9.
The permittee shall not build, erect, install, or use any article, machine, equipment
or process, the use of which conceals an emission which would otherwise
constitute a violation of an applicable standard. Such concealment includes, but is
not limited to, the use of gaseous diluents to achieve compliance with an opacity
standard or with a standard which is based on the concentration of a pollutant in
the gases discharged to the atmosphere [40 CFR § 60.12].
10.
With respect to compliance with all New Source Performance Standards (NSPS)
of 40 CFR Part 60, the permittee shall comply with the “General notification and
reporting requirements” found in 40 CFR § 60.19 [40 CFR § 60.19].
11.
The permittee shall provide written notification to NNEPA and US EPA or, if
acceptable to NNEPA, US EPA and the permittee, electronic notification to
NNEPA and US EPA of any reconstruction of an affected facility, or any physical
or operational change to an affected facility which may increase the emission rate
of any air pollutant to which a standard applies, unless that change is specifically
exempted under this permit or in 40 CFR § 60.14(e) [40 CFR § 60.7(a)].
Page 23 of 62
II.F. NSPS for Limestone Handling System, 40 CFR Part 60, Subpart OOO Requirements
The permittee shall comply with the following emission limitations applicable to affected
facilities in the limestone handling system in accordance with 40 CFR Part 60, Subpart
OOO (“Standards of Performance for Nonmetallic Mineral Processing Plants”):
1.
Any transfer point on belt conveyors or any other affected facility shall not
discharge any stack emissions which [40 CFR § 60.672(a)]:
a.
Contain particulate matter in excess of 0.05 g/dscm (0.022 gr/ dscf), and
b.
Exhibit greater than 7 percent opacity.
2.
Any transfer point on belt conveyors or any other affected facility shall not
discharge any fugitive emissions which exhibit greater than 10 percent opacity
[40 CFR § 60.672(b)].
3.
Any crusher at which a capture system is not used shall not discharge fugitive
emissions which exhibit greater than 15 percent opacity [40 CFR § 60.672(c)].
4.
Truck dumping of nonmetallic minerals into any screening operation, feed hopper
or crusher is exempt from the requirements of this 40 CFR § 60.672 [40 CFR §
60.672(d)].
5.
If any transfer point on a conveyor belt or any other affected facility is enclosed in
a building, then each enclosed affected facility must comply with the emission
limits in Conditions II.F.1, II.F.2, and II.F.3, or the building enclosing the affected
facility or facilities must comply with the following emission limits:
6.
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)].
Any baghouse that controls emissions from only an individual, enclosed storage
bin, shall not discharge stack emissions which exhibit greater than 7 percent
opacity [40 CFR § 60.672(f)].
II.G. Monitoring and Testing Requirements to Comply with NSPS for Limestone Handling
System, 40 CFR Part 60, Subpart OOO
Pursuant to the Reopening Permit to this Part 71 Permit issued on November 13, 2003,
the permittee shall comply with the following [40 CFR § 71.6(a)(3)]:
Page 24 of 62
1.
Once per five year permit term, and at such other times as specified by NNEPA,
the permittee shall conduct performance tests for particulate matter emissions
from the exhaust stacks of baghouses DC-9, DC-10, and DC-11 using EPA
Method 5 or Method 17, and furnish US EPA and NNEPA a written report of the
results of such test. The tests shall be conducted at the maximum operating
capacity of the facility being tested. Upon written request from the permittee,
NNEPA may approve the conducting of performance tests at a lower specified
production rate. In addition to testing once per five year permit term, if during any
12 consecutive month period visible emissions are observed three times from any
one baghouse, the permittee shall conduct a performance test on that baghouse
within 120 days of the third observation. All observations of visible emissions by
the permittee, US EPA, or NNEPA shall count toward the 12 month total.
2.
The permittee shall conduct a weekly visual emission survey of the exhaust stacks
of baghouses DC-9, DC-10, and DC-11. The weekly survey shall be conducted
while the equipment is operating, and during daylight hours, by a person certified
in EPA Method 9 (Visual Determination of the Opacity of Emissions from
Stationary Sources). If any visible emissions are observed, the permittee shall
conduct an opacity test using EPA Method 9 within 24 hours while the equipment
is operating in accordance with 40 CFR § 60.675.
3.
For each visible emission observation or Method 9 opacity test, the permittee
shall record and maintain the following records:
a.
the date and time of the observation and the name of the observer.
b.
the unit ID number.
c.
a statement of whether visible emissions were detected, and if so, whether
they were observed continuously or intermittently.
a.
the results of the Method 9 test, if required.
II.H. NSPS for Stationary Compression Ignition Internal Combustion Engines, 40 CFR
Part 60, Subpart IIII Requirements
The following requirements apply to the emergency fire pump (NGS-120A) in
accordance with 40 CFR Part 60, Subpart IIII (“Standards of Performance for Stationary
Compression Ignition Internal Combustion Engines”):
1.
Emissions from engine NGS-120A shall not exceed the following [40 CFR §
60.4205(c)]:
a.
4.0 g/KW-hr or 3.0 g/HP-hr for NMHC and NOX emissions.
b.
0.2 g/KW-hr or 0.15 g/HP-hr for PM emissions.
Page 25 of 62
2.
3.
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.
The permittee shall comply with the following operating requirements [40 CFR §
60.4211(a)]:
a.
Operate and maintain the emergency fire pump (NGS-120A) according to
the manufacturer's emission-related written instructions;
b.
Change only those emission-related settings that are permitted by the
manufacturer; and
c.
Meet the requirements of 40 CFR Parts 89, 94 and/or 1068, as applicable.
4.
The fire pump must be certified to the emission standards in Condition II.H.1 for
the same model year and NFPA nameplate engine power. The engine must be
installed and configured according to the manufacturer's emission-related
specifications. [40 CFR § 60.4211(c)]
5.
The operation hours for the emergency fire pump (NGS-120A) shall be limited to
the following [40 CFR § 60.4211(f)]:
a.
No use time limit for emergency situations.
b.
A maximum of 100 hours per calendar year for maintenance/testing and
emergency demand response, as specified below, and for non-emergency
situations:
(i)
Maintenance checks and readiness testing, provided that the tests
are recommended by federal, state or local government, the
manufacturer, the vendor, the regional transmission organization or
equivalent balancing authority and transmission operator, or the
insurance company associated with the engine.
Page 26 of 62
c.
(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.
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.
2.
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.
The permittee shall follow the preconstruction review and notification
requirements specified in 40 CFR § 63.5.
Page 27 of 62
3.
The permittee shall follow requirements for compliance with emission standards
and operation and maintenance requirements specified in 40 CFR § 63.6(b).
4.
Monitoring shall be conducted as set forth in 40 CFR § 63.8 and the relevant
standard.
5.
The permittee shall follow the notification requirements specified in 40 CFR §
63.9.
6.
The permittee shall maintain files of all information (including all reports and
notifications) required by 40 CFR Part 63 recorded in a form suitable and readily
available for expeditious inspection and review. The files shall be retained for at
least 5 years following the date of each occurrence, measurement, maintenance,
corrective action, report, or record. At a minimum, the most recent 2 years of data
shall be retained on site. The remaining 3 years of data may be retained off site.
Such files may be maintained on microfilm, on a computer, on computer floppy
disks, on magnetic tape disks, on microfiche, or on other forms of electronic
storage. [40 CFR § 63.10(b)(1)]
II.J. NESHAP for Coal- and Oil-Fired Electric Utility Steam Generating Units, 40 CFR
Part 63, Subpart UUUUU Requirements
Boilers U1, U2, and U3 are subject to 40 CFR Part 63, Subpart UUUUU (“National
Emission Standards for Hazardous Air Pollutants: Coal- and Oil-Fired Electric Utility
Steam Generating Units”) and shall comply with the following requirements:
1.
The permittee shall comply with the following schedule [Extension Approval
Letter Dated January 27, 2014]:
a.
By October 1, 2015, commence construction to incorporate the mercury
control strategy on-site. [Note: The permittee plans to install a calcium
bromide application and powder activated carbon (PAC) injection system
to control the Hg emissions.]
b.
By April 16, 2016, complete on-site construction and comply with all
mercury provisions of this NESHAP.
2.
The permittee shall submit progress reports to both NNEPA and U.S. EPA that
indicate the status of completion of each step of the compliance schedule listed in
Condition II.J.1 within 30 days after the completion date for that step [Extension
Approval Letter Dated January 27, 2014].
3.
The permittee shall submit a final report to both NNEPA and U.S. EPA within 30
days after the final compliance deadline describing the chosen control technology
and demonstrating that it is meeting the requirements under this NESHAP
[Extension Approval Letter Dated January 27, 2014].
Page 28 of 62
4.
5.
6.
7.
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.
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]
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.
The permittee shall comply with the applicable compliance, monitoring, testing,
notification, recordkeeping, and reporting requirements under 40 CFR Part 63,
Subpart UUUUU, specified in Attachment C of this permit by. The requirements
pertaining to Hg emissions are not applicable until April 16, 2016.
II.K. NESHAP for Industrial, Commercial, and Institutional Boilers and Process Heaters,
40 CFR Part 63, Subpart DDDDD Requirements
The following requirements apply to the auxiliary boilers (AUX A and AUX B) in
accordance with 40 CFR Part 63, Subpart DDDDD (“National Emission Standards for
Page 29 of 62
Hazardous Air Pollutants for Major Sources: Industrial, Commercial, and Institutional
Boilers and Process Heaters”):
1.
The permittee shall comply with the applicable requirements specified under 40
CFR Part 63, Subpart DDDDD by January 31, 2016 [40 CFR § 63.7495(b)].
2.
The permittee shall not operate either of the auxiliary boilers (AUX A and AUX
B) for more than 10% of the annual capacity, in order to quality for “limited-use”
units [40 CFR §§ 71.6(a)(1) and 63.7575(d)(3)].
3.
The permittee shall complete a tune-up as specified below for each of the
auxiliary boilers every 5 years [40 CFR § 63.7500(c) and 63.7540(a)(10)].
a.
As applicable, inspect the burner and clean or replace any components of
the burner as necessary (the permittee may delay the burner inspection
until the next scheduled unit shutdown). Units that produce electricity for
sale may delay the burner inspection until the first outage, not to exceed
36 months from the previous inspection. At units where entry into a piece
of process equipment or into a storage vessel is required to complete the
tune-up inspections, inspections are required only during planned entries
into the storage vessel or process equipment;
b.
Inspect the flame pattern, as applicable, and adjust the burner as necessary
to optimize the flame pattern. The adjustment should be consistent with
the manufacturer's specifications, if available;
c.
Inspect the system controlling the air-to-fuel ratio, as applicable, and
ensure that it is correctly calibrated and functioning properly (the
permittee may delay the inspection until the next scheduled unit
shutdown). Units that produce electricity for sale may delay the inspection
until the first outage, not to exceed 36 months from the previous
inspection;
d.
Optimize total emissions of CO. This optimization should be consistent
with the manufacturer's specifications, if available, and with any NOX
requirement to which the unit is subject;
e.
Measure the concentrations in the effluent stream of CO in parts per
million, by volume, and oxygen in volume percent, before and after the
adjustments are made (measurements may be either on a dry or wet basis,
as long as it is the same basis before and after the adjustments are made).
Measurements may be taken using a portable CO analyzer; and
f.
Maintain on-site and submit, if requested by the Administrator, an annual
report containing the information specified below:
Page 30 of 62
(i)
The concentrations of CO in the effluent stream in parts per
million by volume, and oxygen in volume percent, measured at
high fire or typical operating load, before and after the tune-up of
the boiler or process heater; and
(ii)
A description of any corrective actions taken as a part of the tuneup.
4.
The permittee shall complete an initial tune-up for the affected boilers (AUX A
and AUX B) no later than January 31, 2016. If the affected boilers have not
operated between March 21, 2011 and January 31, 2016, the permittee shall
complete an initial tune-up no later than 30 days after the re-start of the affected
boilers [40 CFR § 63.7510(e) and (j)].
5.
The permittee shall keep the following records:
6.
(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)].
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;
Page 31 of 62
(d)
The total operating time during the reporting period;
(e)
The date of the most recent tune-up for each unit; and the date of the most
recent burner inspection if it was delayed until the next scheduled or
unscheduled unit shutdown.
II.L. NESHAP for Stationary Reciprocating Internal Combustion Engines, 40 CFR Part
63, Subpart ZZZZ Requirements
The following requirements apply to the diesel-fired emergency generators EG2, EG3,
NPG-746, and the emergency fire pump NGS-120A in accordance with 40 CFR Part 63,
Subpart ZZZZ (“National Emissions Standards for Hazardous Air Pollutants for
Stationary Reciprocating Internal Combustion Engines”):
1.
For emergency fire pump NGS-120A, compliance with the requirements of NSPS
for Stationary Compression Ignition Internal Combustion Engines, 40 CFR Part
60, Subpart IIII, specified in Condition II.H, fulfills the requirements of this
NESHAP [40 CFR § 63.6590(c)].
2.
The permittee shall comply with the following work practice requirements for
engines EG2, EG3, and NPG-746 [40 CFR § 63.6602]:
a.
Change oil/filter every 500 hours of operation or annually, whichever
comes first;
b.
Inspect air cleaner every 1,000 hours of operation or annually, whichever
comes first, and replace as necessary;
c.
Inspect hoses/belts every 500 hours of operation or annually, whichever
comes first, and replace as necessary; and
d.
Minimize the engine's time spent at idle and minimize the engine's startup
time at startup to a period needed for appropriate and safe loading of the
engine, not to exceed 30 minutes, after which time the non-startup
emission limitations apply.
3.
For the emergency generators EG2 and NPG-746, the permittee shall use ultra
low sulfur diesel fuel (sulfur content = 15 ppmv) after January 1, 2015, except
that any existing diesel fuel purchased (or otherwise obtained) prior to January 1,
2015, may be used until depleted [40 CFR § 63.6604(b)].
4.
The permittee shall install a non-resettable hour meter for each of emergency
generators EG2, EG3, and NPG-746 [40 CFR § 63.6625(f)].
5.
The operation hours for each of the emergency generators EG2, EG3, and NPG746 shall be limited to the following [40 CFR § 63.6640(f)]:
Page 32 of 62
a.
No use time limit for emergency situations.
b.
A maximum of 100 hours per calendar year for maintenance/testing and
emergency demand response, as specified below, and for non-emergency
situations specified in Condition II.L.4.c:
c.
6.
(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.
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.
The permittee shall keep the following records for the emergency generators EG2,
EG3, and NPG-746 [40 CFR § 63.6655]:
a.
Records of the maintenance conducted on the stationary RICE [40 CFR §
63.6655(e)].
b.
Records of the hours of operation of the engine that is recorded through
the non-resettable hour meter. The permittee shall document how many
hours are spent for emergency operation, including what classified the
operation as an emergency and how many hours are spent for nonemergency operation. If the engine is used for the purposes specified in
Condition II.L.5.b.(ii) or (iii), the permittee must keep records of the
notification of the emergency situation and the date, start time, and end
time of engine operation [40 CFR § 63.6655(f)].
Page 33 of 62
II.M. PM CEMS Requirements
After the PM CEMS associated with boilers U1, U2, U3 operate properly, the permittee
shall comply with the following requirements for the PM CEMS:
1.
The permittee may shall operate and maintain a PM CEMS for each of the stacks
associated with boilers U1, U2, and U3 to demonstrate compliance with the PM
emission limit specified in Condition II.A.2.b. [40 CFR § 71.6(a)(3)]
2.
The operation and maintenance of PM CEMS shall comply with the applicable
requirements for PM CEMS specified in NESHAP, Subpart UUUUU (see
Attachment C to this permit). [40 CFR § 71.6(a)(3)]
II.N. CAM Requirements [40 CFR Part 64]
Before the PM CEMS associated with boilers U1, U2, and U3 operate properly, the
permittee shall comply with the following CAM requirements for each of the boilers U1,
U2, and U3:
1.
Monitoring
a.
b.
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.
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
Page 34 of 62
a continuous basis by a data acquisition handling system.
b.
2.
3.
(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.
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)]
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.
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
Page 35 of 62
each boiler unit.
d.
The wet limestone scrubber on/off signal of each boiler unit.
4.
At all times, the permittee shall maintain the monitoring equipment, including but
not limited to, maintaining necessary parts for routine repairs of the monitoring
equipment. [40 CFR § 64.7(b)]
5.
Except for, as applicable, monitoring malfunctions, associated repairs, and
required quality assurance or control activities (including, as applicable,
calibration checks and required zero and span adjustments), the permittee shall
conduct all monitoring in continuous operation (or shall collect data at all required
intervals) at all times that the pollutant-specific emissions unit is operating. Data
recorded during monitoring malfunctions, associated repairs, and required quality
assurance or control activities shall not be used for purposes of this permit,
including data averages and calculations, or fulfilling a minimum data availability
requirement, if applicable. The permittee shall use all the data collected during all
other periods in assessing the operation of the control device and associated
control system. A monitoring malfunction is any sudden, infrequent, not
reasonably preventable failure of the monitoring to provide valid data. Monitoring
failures that are caused in part by poor maintenance or careless operation are not
malfunctions. [40 CFR § 64.7(c)]
6.
Response to excursions or exceedances [40 CFR § 64.7(d)]
a.
Upon detecting an excursion or exceedance, the permittee shall restore
operation of the pollutant-specific emissions unit (including the control
device and associated capture system) to its normal or usual manner of
operation as expeditiously as practicable in accordance with good air
pollution control practices for minimizing emissions. The response shall
include minimizing the period of any startup, shutdown or malfunction
and taking any necessary corrective actions to restore normal operation
and prevent the likely recurrence of the cause of an excursion or
exceedance (other than those caused by excused startup or shutdown
conditions). Such actions may include initial inspection and evaluation,
recording that operations returned to normal without operator action (such
as through response by a computerized distribution control system), or any
necessary follow-up actions to return operation to within the indicator
range, designated condition, or below the applicable emission limitation or
standard, as applicable.
b.
Determination of whether the permittee has used acceptable procedures in
response to an excursion or exceedance will be based on information
available, which may include but is not limited to monitoring results,
review of operation and maintenance procedures and records, and
inspection of the control device, associated capture system, and the
Page 36 of 62
process.
7.
If the permittee identifies a failure to achieve compliance with an emission
limitation or standard for which the approved monitoring did not provide an
indication of an excursion or exceedance while providing valid data, or the results
of compliance or performance testing document a need to modify the existing
indicator ranges or designated conditions, the permittee shall promptly notify
NNEPA and, if necessary, submit a proposed modification to this permit to
address the necessary monitoring changes. Such a modification may include, but
is not limited to, reestablishing indicator ranges or designated conditions,
modifying the frequency of conducting monitoring and collecting data, or the
monitoring of additional parameters. [40 CFR § 64.7(e)]
8.
Based on the results of a determination made under Condition II.N.6.b of this
permit, NNEPA may require the permittee to develop and implement a Quality
Improvement Plan (QIP). In addition, NNEPA may require the implementation of
a QIP if an accumulation of exceedances or excursions exceeds 5 percent duration
of each unit’s (U1-U3) operating time for one calendar quarter. [40 CFR §
64.8(a)]
9.
Reporting and Recordkeeping Requirements [40 CFR § 64.9]
a.
b.
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.
The permittee shall comply with the recordkeeping requirements specified
in Condition III.B of this permit. The permittee shall maintain records of
monitoring data, monitor performance data, corrective actions taken, any
written QIP required pursuant to 40 CFR § 64.8 and any activities
undertaken to implement a QIP, and other supporting information required
Page 37 of 62
to be maintained under 40 CFR Part 64 (such as data used to document the
adequacy of monitoring or records of monitoring maintenance or
corrective actions) [40 CFR § 64.9(b)(1)].
c.
Instead of paper records, the permittee may maintain records on
alternative media, such as microfilm, computer files, magnetic tape disks,
or microfiche, provided that the use of such alternative media allows for
expeditious inspection and review, and does not conflict with other
applicable recordkeeping requirements [40 CFR § 64.9(b)(2)].
II.O. Requirements for Reagent Handling Systems [40 CFR §§ 49.151-161]
Pursuant to Tribal Minor NSR Permit #T-0004-NN, issued on August 26, 2015, the
permittee shall comply with the following requirements for the powdered activated
carbon (PAC) and calcium bromide handling systems:
1.
Vehicle miles travel (VMT) for truck traffic associated with the delivery of PAC
shall not exceed 30 VMT per 12-month period.
2.
VMT for truck traffic associated with the delivery of calcium bromide shall not
exceed 365 VMT per 12-month period.
3.
The permittee shall monitor and maintain records on a calendar month basis of
each PAC deliver, the VMT of each delivery, and determine the 12-month rolling
total.
4.
The permittee shall monitor and maintain records on a calendar month basis of
each calcium bromide deliver, the VMT of each delivery, and determine the 12month rolling total.
5.
At least once during each calendar week, the permittee shall perform a visible
emissions survey for each PAC silo (Silos A and B). The survey shall be
performed during daylight hours by an individual trained in EPA Method 22
while the equipment is in operation. If visible emissions are detected during the
survey, the permittee shall take corrective action so that within 24 hours no visible
emissions are detected.
II.P. Operational Flexibility
1.
Clean Air Act Section 502(b)(10) Changes [40 CFR § 71.6(a)(13)(i)] [NNOPR
§ 404(A)]
a.
The permittee may make Clean Air Act Section 502(b)(10) changes
without applying for a permit revision if those changes do not cause the
facility to exceed emissions allowable under this permit (whether
expressed as a rate of emissions or in terms of total emissions) and are not
Page 38 of 62
modifications under Title I of the Clean Air Act. This class of changes
does not include:
(i)
Changes that would violate applicable requirements (as defined in
40 CFR § 71.2, NNOPR § 102(11)); or
(ii)
Changes that would contravene federally enforceable permit terms
and conditions that are monitoring (including test methods),
recordkeeping, reporting, or compliance certification requirements.
b.
For each proposed Clean Air Act Section 502(b)(10) change, the permittee
shall provide written notification to the Director and the Administrator at
least 7 days in advance of the proposed change. Such notice shall state
when the change will occur and shall describe the change, any resulting
emissions change, and any permit terms or conditions made inapplicable
as a result of the change. The permittee shall attach each notice to its copy
of this permit.
c.
Any permit shield provided in this permit shall not apply to any change
made pursuant to Condition II.P.1.
Page 39 of 62
III. Facility-Wide or Generic Permit Requirements
Conditions in this section of the permit (Section III) apply to all emissions units located at
the facility [See 40 CFR § 71.6(a)(1)].
III.A. Testing Requirements [40 CFR § 71.6(a)(3)]
In addition to the unit-specific testing requirements derived from the applicable
requirements for each individual unit contained in Section II of this permit, the permittee
shall comply with the following generally applicable testing requirements as necessary to
ensure that the required tests are sufficient for compliance purposes:
1.
Submit to NNEPA a source test plan 30 days prior to any required testing. The
source test plan shall include and address the following elements:
1.0 Purpose of the Test
2.0 Source Description and Mode of Operation During Test
3.0 Scope of Work Planned for Test
4.0 Schedule/Dates
5.0 Process Data to be Collected During Test
6.0 Sampling and Analysis Procedures
6.1 Sampling Locations
6.2 Test Methods
6.3 Analysis Procedures and Laboratory Identification
7.0 Quality Assurance Plan
7.1 Calibration Procedures and Frequency
7.2 Sample Recovery and Field Documentation
7.3 Chain of Custody Procedures
7.4 QA/QC Project Flow Chart
8.0 Data Processing and Reporting
8.1 Description of Data Handling and QC Procedures
8.2 Report Content
2.
Unless otherwise specified by an applicable requirement or permit condition in
Section II, all source tests shall be performed at maximum operating rates (90% to
110% of device design capacity).
3.
Only regular operating staff may adjust the processes or emission control device
parameters within two (2) hours before or during a compliance source test. All
adjustments must be logged and a copy of the log submitted with the test report.
No adjustments are to be made within two (2) hours before the start of the tests or
during a test, if those adjustments are a result of consultation before or during the
tests with source testing personnel, equipment vendors, or consultants. Such
adjustments may render the source test invalid.
Page 40 of 62
4.
During each test run and for two (2) hours prior to the test and two (2) hours after
the completion of the test, the permittee shall record the following information:
a.
Visible emissions or COMS data; and
b.
All parametric data which is required to be monitored in Section II for the
emission unit being tested.
5.
Each source test shall consist of at least three (3) valid test runs and the emission
results shall be reported as the arithmetic average of all valid test runs and in the
terms of the emission limit. There must be at least 3 valid test runs, unless
otherwise specified.
6.
Source test reports shall be submitted to NNEPA and U.S. EPA within 60 days of
completing any required source test.
III.B. Recordkeeping Requirements [40 CFR § 71.6(a)(3)(ii)]
In addition to the unit-specific recordkeeping requirements derived from the applicable
requirements for each individual unit and contained in Section II, the permittee shall
comply with the following generally applicable recordkeeping requirements:
1.
2.
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.
The permittee shall retain records of all required monitoring data and support
information for a period of at least 5 years from the date of the monitoring
sample, measurement, report, or application. Support information includes all
calibration and maintenance records, all original strip-chart recordings for
continuous monitoring instrumentation, and copies of all reports required by this
permit.
Page 41 of 62
3.
The permittee shall maintain a file of all measurements, including continuous
monitoring system, monitoring device, and performance testing measurements; all
continuous monitoring system performance evaluations; all continuous
monitoring system or monitoring device calibration checks; adjustments and
maintenance performed on these systems or devices; and all other information
required by 40 CFR Part 60 recorded in a permanent form suitable for inspection.
The file shall be retained for at least five years following the date of such
measurements, maintenance, reports and records [40 CFR § 71.6(a)(3)(ii), 40
CFR § 60.7(f)].
III.C. Reporting Requirements [40 CFR § 71.6 (a)(3)(iii)]
1.
The permittee shall submit to NNEPA and EPA Region 9 reports of any
monitoring required under 40 CFR § 71.6(a)(3)(i)(A), (B), or (C) each six month
reporting period from January 1 to June 30 and from July 1 to December 31. All
reports shall be submitted to NNEPA and US EPA and shall be postmarked by the
30th day following the end of the reporting period. All instances of deviations
from permit requirements must be clearly identified in such reports. All required
reports must be certified by a responsible official consistent with Condition
III.C.4 of this permit.
a.
A monitoring report under this section must include the following:
(i)
The company name and address.
(ii)
The beginning and ending dates of the reporting period.
(iii)
The emissions unit or activity being monitored.
(iv)
The emissions limitation or standard, including operational
requirements and limitations (such as parameter ranges), specified
in the permit for which compliance is being monitored.
(v)
All instances of deviations from permit requirements, including
those attributable to upset conditions and exceedances as defined
under 40 CFR § 64.1, and the date on which each deviation
occurred.
(vi)
If the permit requires continuous monitoring of an emissions limit
or parameter range, the report must include the total operating time
of the emissions unit during the reporting period, the total duration
of excess emissions or parameter exceedances during the reporting
period, and the total downtime of the continuous monitoring
system during the reporting period.
Page 42 of 62
2.
(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.
The permittee shall promptly report to the NNEPA and EPA Regional Office
deviations from permit requirements, including those attributable to upset
conditions, the probable cause of such deviations, and any corrective actions or
preventive measures taken. Where the underlying applicable requirement contains
a definition of “prompt” or otherwise specifies a time frame for reporting
deviations, that definition or time frame shall govern.
Page 43 of 62
Where the underlying applicable requirement does not define prompt or provide a
timeframe for reporting deviations, reports of deviations will be submitted based
on the following schedule:
a.
For emissions of a hazardous air pollutant or a toxic air pollutant (as
identified in the applicable regulation) that continue for more than an hour
in excess of permit requirements, the report must be made by telephonic,
verbal, or facsimile communication within 24 hours of the occurrence.
b.
For emissions of any regulated pollutant, excluding a hazardous air
pollutant or a toxic air pollutant, that continue for more than two hours in
excess of permit requirements, the report must be made by telephonic,
verbal, or facsimile communication within 48 hours of the occurrence.
c.
For all other deviations from permit requirements, the report shall be
submitted with the semi-annual monitoring report required in Condition
III.C.1 of this permit.
3.
If any of the conditions in Condition III.C.2.a or b of this permit are met, the
source must notify NNEPA and US EPA by telephone, facsimile, or electronic
mail sent to [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
Page 44 of 62
substitute products or manufacturing processes for such product that do
not rely on the use of a class I or class II substance, that reduce the overall
risk to human health and the environment, and that are currently or
potentially available, no product identified in 40 CFR § 82.102(b) may be
introduced into interstate commerce unless it bears a warning statement
that complies with the requirements of 40 CFR § 82.106, unless such
labeling is not required under 40 CFR §§ 82.106(b), 82.112(c) or (d),
82.116(a) or 82.118(a). [40 CFR § 82.124(a)(1)(ii)]
2.
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)]
The permittee shall comply with the standards for recycling and emissions
reduction pursuant to 40 CFR Part 82, Subpart F, except as provided for motor
vehicle air conditioners (MVACs) in Subpart B [40 CFR § 82.150(b)]:
a.
Persons opening appliances for maintenance, service, repair, or disposal
must comply with the required practices pursuant to 40 CFR § 82.156.
b.
Equipment used during maintenance, service, repair, or disposal of
appliances must comply with the standards for recycling and recovery
equipment pursuant to 40 CFR § 82.158.
c.
Persons performing maintenance, service, repair, or disposal of appliances
must be certified by an approved technician certification program pursuant
to 40 CFR § 82.161.
d.
Persons disposing of small appliances, MVACs, and MVAC-like
appliances (as defined in 40 CFR § 82.152) must comply with
recordkeeping requirements pursuant to 40 CFR § 82.166.
e.
Persons owning commercial or industrial process refrigeration equipment
must comply with the leak repair requirements pursuant to 40 CFR §
82.156.
f.
Owners/operators of appliances normally containing 50 or more pounds of
refrigerant must keep records of when the refrigerant was purchased and
added to such appliances pursuant to 40 CFR § 82.166.
Page 45 of 62
3.
If the permittee produces, transforms, destroys, imports, or exports a Class I or
Class II controlled substance, the permittee is subject to all the requirements in 40
CFR Part 82, Subpart A, Production and Consumption Controls [40 CFR §
82.1(b)].
4.
If the permittee performs a service on a motor (fleet) vehicle when this service
involves ozone-depleting substance refrigerant (or regulated substitute substance)
in the MVAC, the permittee is subject to all the applicable requirements specified
in 40 CFR Part 82, Subpart B, Servicing of Motor Vehicle Air Conditioners [40
CFR § 82.30(b)].
The term "motor vehicle" as used in Subpart B does not include a vehicle in
which final assembly of the vehicle has not been completed. The term "MVAC"
as used in Subpart B does not include the air-tight sealed refrigeration system
used for refrigerated cargo or system used on passenger buses using HCFC-22
refrigerant [40 CFR § 82.32(c), (d)].
5.
The permittee shall be allowed to switch from any ozone-depleting substance to
any acceptable substitute that is listed in the Significant New Alternatives
Program (SNAP) promulgated pursuant to 40 CFR Part 82, Subpart G.
III.E. Asbestos from Demolition and Renovation [40 CFR Part 61, Subpart M]
The permittee shall comply with the requirements of 40 CFR §§ 61.140 through 61.157
of the National Emission Standard for Asbestos for all demolition and renovation projects
[40 CFR § 61.140].
III.F. Compliance Schedule [40 CFR §§ 71.5(c)(8)(iii) and 71.6(c)(3)]
1.
For applicable requirements with which the source is in compliance, the source
will continue to comply with such requirements.
2.
For applicable requirements that will become effective during the permit term, the
source shall meet such requirements on a timely basis.
Page 46 of 62
IV. Title V Administrative Requirements
IV.A. Fee Payment [NNOPR Subpart VI] [40 CFR § 71.6(a)(7) and § 71.9]
1.
The permittee shall pay an annual permit fee in accordance with the procedures
outlined below. [NNOPR §§ 603(A) and (B)]
a.
The permittee shall pay the annual permit fee by April 1 of each year.
b.
Fee payments shall be remitted in the form of a money order or certified
check made payable to the Navajo Nation Environmental Protection
Agency.
c.
The permittee shall send the fee payment to:
Navajo Nation EPA Air Quality Control Program
Operating Permit Program
P.O. Box 529
Fort Defiance, AZ 86504
2.
The permittee shall submit a fee calculation worksheet form with the annual
permit fee by April 1 of each year. Calculations of actual or estimated emissions
and calculation of the fees owed shall be computed on the fee calculation
worksheets provided by US EPA. Fee payment of the full amount must
accompany each fee calculation worksheet. [40 CFR § 71.6(a)(7) and §
71.9(h)(1)]
3.
The fee calculation worksheet shall be certified by a responsible official
consistent with 40 CFR § 71.5(d). [40 CFR § 71.6(a)(7) and § 71.9(h)(2)]
4.
Basis for calculating annual fee:
The annual emissions fee shall be calculated by multiplying the total tons of
actual emissions of all fee pollutants emitted from the source by the applicable
emissions fee (in dollars/ton) in effect at the time of calculation. Emissions of any
regulated air pollutant that already are included in the fee calculation under a
category of regulated pollutant, such as a federally listed hazardous air pollutant
that is already accounted for as a VOC or as PM10, shall be counted only once in
determining the source’s actual emissions. [NNOPR §§ 602(A) and (B)(1)]
a.
“Actual emissions” means the actual rate of emissions in tpy of any fee
pollutant emitted from a part 71 source over the preceding calendar year.
Actual emissions shall be calculated using each emissions unit’s actual
operating hours, production rates, in-place control equipment, and types of
materials processed, stored, or combusted during the preceding calendar
year. Actual emissions shall not include emissions of any one fee pollutant
Page 47 of 62
in excess of 4,000 TPY, or any emissions that come from insignificant
activities [NNOPR § 102(5)].
b.
Actual emissions shall be computed using methods required by the permit
for determining compliance, such as monitoring or source testing data [40
CFR § 71.6(a)(7) and § 71.9(h)(3)].
c.
If actual emissions cannot be determined using the compliance methods in
the permit, the permittee shall use other federally recognized procedures
[40 CFR § 71.6(a)(7) and § 71.9(e)(2)].
d.
The term “fee pollutant” is defined in NNOPR § 102(24).
e.
The term “regulated air pollutant” is defined in NNOPR § 102(50), except
that for purposes of this permit the term does not include any pollutant that
is regulated solely pursuant to 4 N.N.C. § 1121 nor does it include any
hazardous air pollutant designated by the Director pursuant to 4 N.N.C. §
1126(B).
f.
The permittee should note that the applicable fee is revised each year to
account for inflation, and it is available from NNEPA starting on March 1
of each year.
g.
The total annual fee due shall be the greater of the applicable minimum fee
and the sum of subtotal annual fees for all fee pollutants emitted from the
source. [NNOPR § 602(B)(2)]
5.
The permittee shall retain, in accordance with the provisions of 40 CFR §
71.6(a)(3)(ii), all fee calculation worksheets and other emissions-related data used
to determine fee payment for 5 years following submittal of fee payment.
Emission-related data include emissions-related forms provided by NNEPA and
used by the permittee for fee calculation purposes, emissions-related spreadsheets,
and records of emissions monitoring data and related support information required
to be kept in accordance with 40 CFR § 71.6(a)(3)(ii) [40 CFR § 71.6(a)(7) and §
71.9(i)].
6.
Failure of the permittee to pay fees in a timely manner shall subject the permittee
to assessment of penalties and interest in accordance with NNOPR § 603(C).
7.
When notified by NNEPA of underpayment of fees, the permittee shall remit full
payment within 30 days of receipt of notification [40 CFR § 71.9(j)(2)].
8.
A permittee who thinks an NNEPA assessed fee is in error and wishes to
challenge such fee, shall provide a written explanation of the alleged error to
NNEPA along with full payment of the NNEPA assessed fee. Within 90 days of
receipt of the correspondence, NNEPA shall review the data to determine whether
Page 48 of 62
the assessed fee was in error. If an error was made, the overpayment shall be
credited to the account of the permittee. [40 CFR § 71.9(j)(3)].
IV.B. Blanket Compliance Statement [CAA §§113(a) and 113(e)(1) and 40 CFR § 51.212(c),
§ 52.12(c), § 52.33, § 60.11(g), § 61.12(e), § 71.6(a)(6)(i) and (ii), and § 71.12]
1.
The permittee must comply with all conditions of this Part 71 permit. Any permit
noncompliance, including, but not limited to, violation of any applicable
requirement; any permit term or condition; any fee or filing requirement; any duty
to allow or carry out inspection, entry, or monitoring activities; or any regulation
or order issued pursuant to 40 CFR Part 71 constitutes a violation of the Clean Air
Act and is grounds for enforcement action; permit termination, revocation and
reissuance, or modification; or denial of a permit renewal application. It shall not
be a defense for a permittee in an enforcement action that it would have been
necessary to halt or reduce the permitted activity in order to maintain compliance
with the conditions of this permit [CAA § 113(a); 40 CFR §§ 71.6(a)(6)(i) and
(ii), 71.12].
2.
Determinations of deviations, continuous or intermittent compliance status, or
violations of this permit are not limited to the applicable testing or monitoring
methods required by the underlying regulations or this permit; other credible
evidence (including any evidence admissible under the Federal Rules of
Evidence) must be considered in such determinations. [CAA § 113(a) and
113(e)(1); 40 CFR § 51.212(c), § 52.12(c), § 52.33, § 60.11(g), and § 61.12(e)]
IV.C. Compliance Certifications [40 CFR § 71.6(c)(1), (5)] [NNOPR § 302(I)]
1.
The permittee shall submit to NNEPA and US EPA Region 9 a semi-annual
certification of compliance with permit terms and conditions, including emission
limitations, standards, or work practices, postmarked by January 31 and July 31 of
each year and covering the previous six-month period ending on December 31
and June 30, respectively. The compliance certification shall be certified as to
truth, accuracy, and completeness by the permit-designated responsible official
consistent with Condition III.C.4 of this permit [40 CFR § 71.6(c)(1), (5)].
2.
The certification shall include the following [40 CFR § 71.6(c)(5)(iii)]:
a.
Identification of each permit term or condition that is the basis of the
certification.
b.
Identification of the method(s) or other means used for determining the
compliance status of each term and condition during the certification
period, and whether such methods or other means provide continuous or
intermittent data.
c.
The compliance status of each term and condition of the permit for the
period covered by the certification based on the method or means
Page 49 of 62
designated above. The certification shall identify each deviation and take
it into account in the compliance certification. The certification shall
identify as possible exceptions to compliance any periods during which
compliance is required but an excursion or exceedance has occurred
pursuant to this permit.
d.
Whether compliance with each permit term was continuous or
intermittent.
e.
If necessary, the permittee also shall identify any other material
information that must be included in the certification to comply with
Section 113(c)(2) of the Clean Air Act, which prohibits knowingly
making a false certification or omitting material information.
IV.D. Duty to Provide and Supplement Information [40 CFR § 71.6(a)(6)(v), 40 CFR §
71.5(b)]
The permittee shall furnish to NNEPA and US EPA Region 9, within a reasonable time,
any information that NNEPA and US EPA Region 9 may request in writing to determine
whether cause exists for modifying, revoking and reissuing, or terminating the permit, or
to determine compliance with the permit. Upon request, the permittee shall also furnish
to NNEPA and US EPA Region 9 copies of records that are required to be kept pursuant
to the terms of the permit, including information claimed to be confidential. Information
claimed to be confidential should be accompanied by a claim of confidentiality according
to the provisions of 40 CFR Part 2, Subpart B. The permittee, upon becoming aware that
any relevant facts were omitted or incorrect information was submitted in the permit
application, shall promptly submit such supplementary facts or corrected information.
The permittee shall also provide additional information as necessary to address any
requirements that become applicable to the facility after this permit is issued.
IV.E. Submissions [40 CFR § 71.5(d), § 71.6(a)(iii)(A) and (c)(1), and § 71.9(h)(2)]
Any document required to be submitted with this permit shall be certified by a
responsible official as to truth, accuracy, and completeness. Such certifications shall
state that based on information and belief formed after reasonable inquiry, the statements
and information in the document are true, accurate, and complete.
All documents required to be submitted, including reports, test data, monitoring data,
notifications, compliance certifications, fee calculation worksheets, and applications for
renewals and permit modifications shall be submitted to NNEPA and US EPA Region 9:
Navajo Nation Air Quality Control Program
Operating Permit Program
P.O. Box 529
Fort Defiance, AZ 86504
Page 50 of 62
and
Director, Air Division (Attn: AIR-1)
EPA Region IX
75 Hawthorne Street
San Francisco, CA 94105
IV.F. Severability Clause [40 CFR § 71.6(a)(5)]
The provisions of this permit are severable, and in the event of any challenge to any
portion of this permit, or if any portion is held invalid, the remaining permit conditions
shall remain valid and in force.
IV.G. Permit Actions [40 CFR § 71.6(a)(6)(iii)]
This permit may be modified, revoked, reopened, and reissued, or terminated for cause.
The filing of a request by the permittee for a permit modification, revocation and
reissuance, or termination, or of a notification of planned changes or anticipated
noncompliance, does not stay any permit condition.
IV.H Administrative Permit Amendments [40 CFR § 71.7(d)] [NNOPR § 405(C)]
The permittee may implement the changes outlined in subparagraphs (1) through (5)
below immediately upon submittal of the request for the administrative revision. The
permittee may request the use of administrative permit amendment procedures for a
permit revision that:
1.
Corrects typographical errors.
2.
Identifies a change in the name, address, or phone number of any person
identified in the permit, or provides a similar minor administrative change at the
source.
3.
Requires more frequent monitoring or reporting by the permittee.
4.
Allows for a change in ownership or operational control of a source where the
NNEPA determines that no other change in the permit is necessary, provided that
a written agreement containing a specific date for transfer of permit
responsibility, coverage, and liability between the current and new permittee has
been submitted to the NNEPA;
5.
Incorporates into the Part 71 permit the requirements from preconstruction review
permits authorized under an EPA-approved program, provided that such a
program meets procedural requirements substantially equivalent to the
requirements of 40 CFR §§ 71.7, 71.8 and 71.10 that would be applicable to the
Page 51 of 62
change if it were subject to review as a permit modification, and compliance
requirements substantially equivalent to those contained in 40 CFR § 71.6.
6.
Incorporates any other type of change which NNEPA has determined to be similar
to those listed above in subparagraphs (1) through (5).
IV.I. Minor Permit Modifications [40 CFR § 71.7(e)(1)] [NNOPR § 405(D)]
1.
2.
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.
Notwithstanding the list of changes eligible for minor permit modification
procedures in paragraph (1) above, minor permit modification procedures may be
used for permit modifications involving the use of economic incentives,
marketable permits, emissions trading, and other similar approaches, to the extent
that such minor permit modification procedures are explicitly provided for in an
applicable implementation plan or in applicable requirements promulgated by
EPA.
Page 52 of 62
3.
An application requesting the use of minor permit modification procedures shall
meet the requirements of 40 CFR § 71.5(c) and shall include the following:
a.
A description of the change, the emissions resulting from the change, and
any new applicable requirements that will apply if the change occurs;
b.
The permittee's suggested draft permit;
c.
Certification by a responsible official, consistent with 40 CFR § 71.5(d),
that the proposed modification meets the criteria for use of minor permit
modification procedures and a request that such procedures be used; and
d.
Completed forms for NNEPA and US EPA to use to notify affected States
as required under 40 CFR § 71.8.
e.
If the requested permit revision would affect existing compliance plans or
schedules, related progress reports, or certification of compliance
requirements, and an outline of such effects.
4.
The permittee may make the change proposed in its minor permit modification
application immediately after submittal of such application. After the permittee
makes the change allowed by the preceding sentence, and until NNEPA takes any
of the actions specified in NNOPR § 405(D)(6)(a) through (c), the permittee must
comply with both the applicable requirements governing the change and the
proposed permit terms and conditions. During this time period, the permittee need
not comply with the existing permit terms and conditions it seeks to modify.
However, if the permittee fails to comply with its proposed permit terms and
conditions during this period, the existing permit terms and conditions it seeks to
modify may be enforced against it.
5.
The permit shield under 40 CFR § 71.6(f) may not extend to minor permit
modifications [40 CFR § 71.7(e)(1)(vi)].
IV.J. Group Processing of Minor Permit Modifications [40 CFR § 71.7(e)(2)]
1.
Group processing of modifications by NNEPA may be used only for those permit
modifications:
a.
That meet the criteria for minor permit modification procedures under
Condition IV.I.1 of this permit; and
b.
That collectively are below the threshold level of 10 percent of the
emissions allowed by the permit for the emissions unit for which the
change is requested, 20 percent of the applicable definition of major
source in 40 CFR § 71.2, or 5 tons per year, whichever is least.
Page 53 of 62
2.
An application requesting the use of group processing procedures shall meet the
requirements of 40 CFR § 71.5(c) and shall include the following:
a.
A description of the change, the emissions resulting from the change, and
any new applicable requirements that will apply if the change occurs.
b.
The permittee's suggested draft permit.
c.
Certification by a responsible official, consistent with 40 CFR § 71.5(d),
that the proposed modification meets the criteria for use of group
processing procedures and a request that such procedures be used.
d.
A list of the permittee's other pending applications awaiting group
processing, and a determination of whether the requested modification,
aggregated with these other applications, equals or exceeds the threshold
set under Condition IV.J.1.b above.
e.
Certification that the permittee has notified US EPA of the proposed
modification. Such notification need only contain a brief description of
the requested modification.
f.
Completed forms for NNEPA to use to notify affected States as required
under 40 CFR § 71.8 and US EPA as required under 40 CFR § 71.10(d).
3.
The permittee may make the changes proposed in its minor permit modification
application immediately after it files such application. After the source makes the
changes allowed by the preceding sentence, and until NNEPA takes any of the
actions specified in NNOPR § 405(D)(6)(a) through (c), the permittee must
comply with both the applicable requirements governing the change and the
proposed permit terms and conditions. During this time period, the permittee need
not comply with the existing permit terms and conditions it seeks to modify.
However, if the permittee fails to comply with its proposed permit terms and
conditions during this time period, the existing permit terms and conditions it
seeks to modify may be enforced against it.
4.
The permit shield under 40 CFR § 71.6(f) may not extend to group processing of
minor permit modifications [40 CFR § 71.7(e)(2)(vi)].
IV.K. Significant Permit Modifications [40 CFR § 71.7(e)(3)] [NNOPR § 405(E)]
1.
The permittee must request the use of significant permit modification procedures
for those modifications that:
a.
Do not qualify as minor permit modifications or as administrative
amendments.
Page 54 of 62
b.
Are significant changes in existing monitoring permit terms or conditions.
c.
Are relaxations of reporting or recordkeeping permit terms or conditions.
2.
Nothing herein shall be construed to preclude the permittee from making changes
consistent with Part 71 that would render existing permit compliance terms and
conditions irrelevant.
3.
The permittee must meet all requirements of Part 71 for applications for
significant permit modifications. For the application to be determined complete,
the permittee must supply all information that is required by 40 CFR § 71.5(c) for
permit issuance and renewal, but only that information that is related to the
proposed change [40 CFR §§ 71.7(e)(3)(ii) and 71.5(a)(2)].
IV.L. Reopening for Cause [40 CFR § 71.7(f)]
NNEPA shall reopen and revise the permit prior to expiration under any of the following
circumstances:
1.
Additional applicable requirements under the Clean Air Act become applicable to
a major Part 71 source with a remaining permit term of 3 or more years.
2.
Additional requirements (including excess emissions requirements) become
applicable to an affected source under the acid rain program. Upon approval by
the Administrator, excess emissions offset plans shall be deemed to be
incorporated into the permit.
3.
NNEPA or US EPA determines that the permit contains a material mistake or that
inaccurate statements were made in establishing the emissions standards or other
terms or conditions of the permit.
4.
NNEPA or US EPA determines that the permit must be revised or revoked to
assure compliance with the applicable requirements.
IV.M. Property Rights [40 CFR § 71.6(a)(6)(iv)]
This permit does not convey any property rights of any sort, or any exclusive privilege.
IV.N. Inspection and Entry [40 CFR § 71.6(c)(2)]
Upon presentation of credentials and other documents as may be required by law, the
permittee shall allow authorized representatives from NNEPA and US EPA to perform
the following:
Page 55 of 62
1.
Enter upon the permittee’s premises where a Part 71 source is located or
emissions-related activity is conducted, or where records must be kept under the
conditions of this permit;
2.
Have access to and copy, at reasonable times, any records that must be kept under
the conditions of this permit;
3.
Inspect at reasonable times any facilities, equipment (including monitoring and air
pollution control equipment), practices, or operations regulated or required under
the permit; and
4.
As authorized by the Clean Air Act, sample or monitor at reasonable times
substances or parameters for the purpose of assuring compliance with the permit
or applicable requirements.
IV.O. Emergency Provisions [40 CFR § 71.6(g)]
1.
2.
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.
An "emergency" means any situation arising from sudden and reasonably
unforeseeable events beyond the control of the permittee, including acts of God,
which situation requires immediate corrective action to restore normal operation,
Page 56 of 62
and that causes the source to exceed a technology-based emissions limitation
under this permit due to unavoidable increases in emissions attributable to the
emergency. An emergency shall not include noncompliance to the extent caused
by improperly designed equipment, lack of preventive maintenance, careless or
improper operation, or operator error.
IV.P. Transfer of Ownership or Operation [40 CFR § 71.7(d)(1)(iv)]
A change in ownership or operational control of this facility may be treated as an
administrative permit amendment if the NNEPA determines no other change in this
permit is necessary and provided that a written agreement containing a specific date for
transfer of permit responsibility, coverage, and liability between the current and new
permittee has been submitted to NNEPA.
IV.Q. Off Permit Changes [40 CFR § 71.6(a)(12)] [NNOPR § 404(B)]
The permittee is allowed to make certain changes without a permit revision, provided that
the following requirements are met:
1.
Each change is not addressed or prohibited by this permit;
2.
Each change must comply with all applicable requirements and may not violate
any existing permit term or condition;
3.
Changes under this provision may not include changes or activities subject to any
requirement under 40 CFR Parts 72 through 78 or that are modifications under
any provision of Title I of the Clean Air Act;
4.
The permittee must provide contemporaneous written notice to NNEPA and US
EPA Region 9 of each change, except for changes that qualify as insignificant
activities under 40 CFR § 71.5(c)(11). The written notice must describe each
change, the date of the change, any change in emissions, pollutants emitted and
any applicable requirements that would apply as a result of the change;
5.
The permit shield does not apply to changes made under this provision; and
6.
The permittee must keep a record describing all changes that result in emissions
of any regulated air pollutant subject to any applicable requirement not otherwise
regulated under this permit, and the emissions resulting from those changes.
IV.R. Permit Expiration and Renewal [40 CFR §§ 71.5(a)(1)(iii), 71.6(a)(11), and 71.7(b) and
(c)]
1.
This permit shall expire upon the earlier occurrence of the following events:
a.
five (5) years elapses from the date of issuance; or
Page 57 of 62
b.
the source is issued a Part 70 permit by NNEPA, provided that EPA has
granted the Navajo Nation treatment as a state and primacy for a Part 70
program and that NNEPA issues the permit consistent with the VCA.
2.
Expiration of this permit terminates the permittee’s right to operate unless a
timely and complete permit renewal application has been submitted on or before a
date 6 months, but not more than 18 months, prior to the date of expiration of this
permit.
3.
If the permittee submits a timely and complete permit application for renewal that
is consistent with 40 CFR § 71.5(a)(2), but NNEPA has failed to issue or deny the
renewal permit, then the permit shall not expire until the renewal permit has been
issued or denied and any permit shield granted pursuant to 40 CFR § 71.6(f) may
extend beyond the original permit term until renewal.
4.
The permittee’s failure to have a Part 71 permit is not a violation of 40 CFR Part
71 until NNEPA takes final action on the permit renewal application. This
protection shall cease to apply if, subsequent to the completeness determination,
the permittee fails to submit any additional information identified as being needed
to process the application by the deadline specified in writing by NNEPA.
5.
Renewal of this permit is subject to the same procedural requirements that apply
to initial permit issuance, including those for public participation and affected
State and tribal review.
6.
The application for renewal shall include the current permit number, description
of permit revisions and off-permit changes that occurred during the permit term,
any applicable requirements that were promulgated and not incorporated into the
permit during the permit term, and other information required by the application
form.
IV.S. Additional Permit Conditions [Voluntary Compliance Agreement, Article 6]
This permit is issued pursuant to the Voluntary Compliance Agreement between the
permittee and the Navajo Nation. The permittee shall comply with the terms of this
permit and shall be subject to enforcement of the permit by the Navajo Nation EPA,
pursuant to the terms of the Voluntary Compliance Agreement. The permittee’s
agreement to comply is effective upon the permittee’s written acceptance of the permit
and expires at the end of the permit term, unless the permit is renewed. The permittee’s
agreement to comply may be withdrawn during the permit term only if the Voluntary
Compliance Agreement is terminated or expires as provided in that Agreement.
IV.T. Part 71 Permit Enforcement [Voluntary Compliance Agreement, Section 5.4.5; 40 CFR
§ 71.12]
Page 58 of 62
1.
2.
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.
Violations of any applicable requirement; any permit term or condition; any fee or
filing requirement; any duty to allow or carry out inspection, entry, or monitoring
activities; or any regulation or order issued pursuant to 40 CFR Part 71 are
violations of the Clean Air Act and are subject to full Federal enforcement
authorities available under the Clean Air Act.
Page 59 of 62
Attachment A
Dust Control Plan
Page 60 of 62
Attachment B
Phase II Acid Rain Permit Renewal
Page 61 of 62
Attachment C
NESHAP for Coal- and Oil-Fired Electric Utility
Steam Generating Units,
40 CFR Part 63, Subpart UUUUU –
Compliance, Monitoring, Testing, Notification,
Recordkeeping, and Reporting Requirements
Page 62 of 62
TH E NAVAJO NATION
RUSSELL BEGAYE PRES I DE NT
JONATHAN NEZ VICE PRESIDENT
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
Navajo Generating Station
Permit No. NN-OP-15-06
1.
Facility Information
a. Permittee
Navajo Generating Station
5 Miles East of Page, off U.S. Highway 98
Page, Arizona 86040
Mailing Address:
P.O. Box 850
Page, Arizona 86040
Managing Participant Name:
Salt River Project Agricultural Improvement
and Power District (SRP)*
Managing Participant Mailing Address: P.O. Box 52025, PAB 352
Phoenix, Arizona 85072-2025
*Note: This facility is co-owned by 6 entities. SRP is listed as the managing
participant in this permit since it acts as the facility operator, and has accepted the
responsibility to obtain environmental permits for Navajo Generating Station, including
an Acid Rain permit and Part 71 Permit. In addition to SRP (21.7%), the other 5 coowners of this facility are:
1.
2.
3.
4.
U.S. Bureau of Reclamation (USBR) (24.3%)
Los Angeles Department of Water and Power (LADWP) (21.2%)
Arizona Public Service Company (APS) (14.0%)
Nevada Power Company (NPC) (11.3%)
5.
Tucson Electric Power (TEP) (7.5%)
b. Contact Information
Facility Contact:
Paul Ostapuk
O&M Manager
Phone: (928) 645-6577
Facsimile: (928) 645-7298
Responsible Official:
Robert K. Talbot
Plant Manager
Phone: (928) 645-6217
Facsimile: (928) 645-7298
c. Description_of_Operations,_Products
The facility is a 2,250 net Megawatt coal-fired power plant. Bituminous coal is mined by
Peabody Energy at the Kayenta Mine complex and delivered by electric rail to NGS.
Coal is then transferred via enclosed conveyor systems to the boilers or to a storage pile
for later use.
The management of coal combustion residues and the delivery of limestone for the SO2
scrubbers is contracted to a third party entity but SRP remains the responsible party for
truck loading and unloading operations, material transfer, storage, and disposal activities.
Coal combustion residues include fly ash, bottom ash, and scrubber byproducts. Bottom
ash and scrubber byproducts are handled in a wet state which minimizes the potential for
dust emissions.
d. History
The facility consists of three (3) coal-fired utility boilers and two oil-fired auxiliary
boilers. The permittee receives the coal, which has an average sulfur content between
0.5% and 0.75% by weight, from a nearby coal mine. Coal-fired boilers U1, U2, and
U3 and oil-fired auxiliary boilers AUX-A and AUX-B commenced construction in
1970. The construction of these boilers predated EPA's preconstruction permit
regulations.
Particulate emissions from boilers U1 through U3 are controlled by Electrostatic
Precipitators (ESP). Flue Gas Desulfurization (FGD) systems for SO2 control were
installed in 1997, 1998, and 1999 on boilers U3, U2, and U1, respectively. The
associated limestone handling system was constructed in 1997. In 2008, the source
received a PSD permit to install Low-NOX burners (LNBs) and Separated Over-fire Air
(SOFA) systems on the three existing boilers. The LNB/SOFA systems were installed
in 2009, 2010, and 2011 on boilers U3, U2, and U1, respectively. The permittee also
plan to install mercury control systems in 2015 for boilers U1 through U1 through U3
using powdered activated carbon (PAC) and calcium bromide.
On February 9, 2015, the permittee submitted a minor NSR permit application to both
US EPA and NNEPA for the construction of a refined coal system as part of the coal
Page 2 of 29
handling operation at the facility. The refined coal system will be owned and operated
by a third-party which will be contracted out by SRP. This NSR permit application is
currently reviewed by US EPA.
e. Existing Approvals
The source has been operating under Part 71 Operating Permit NN-ROP-05-06, issued
on July 3, 2008, and the following approvals:
(a)
PSD Permit #AZ 08-01, issued on November 20, 2008.
(b)
Title V Permit Reopening #NN-ROP-05-06-A, issued on October 28, 2011.
(c)
PSD Permit Amendment #AZ 08-01A, issued on February 6, 2012; amended on
August 26, 2015.
(d)
Tribal Minor NSR Permit #T-0004-NN, issued on August 26, 2015
f. Proposed Modifications to the Part 71 Permit:
The permittee requested the following changes made to their Part 71 permit:
(1)
Changes to the maximum heat input capacity of the boilers:
The maximum heat input capacity for each of the boilers U1, U2, and U3 has
been reduced from 7,725 MMBtu/hr to 7,410 MMBtu/hr. This change was
requested by the permittee because the heating value of coal received at this
plant has decreased in recent years and the revised heat input of 7,410
MMBtu/hr for each boiler better reflects the estimated maximum boiler
capacity. This change will not result in increases of emissions from these units
and is considered a minor permit modification.
(2)
Revise the insignificant activities listed:
The list of insignificant activities and emissions in Section 1.j of this Statement
of Basis has been updated based on information submitted by the permittee on
July 24, 2014. The new emergency fire pump (NGS-120A) is subject to the
New Source Performance Standards (NSPS) for Stationary Compression
Ignition Internal Combustion Engines (40 CFR Part 60, Subpart IIII) and the
applicable requirements of this NSPS will be included in this Part 71 permit.
These changes are considered a significant permit modification.
(3)
Update the unit description for coal hopper feeders (L1-L12):
The permittee installed a wet dust suppression system (Mee Fog System) to
control the twelve (12) coal hopper feeders (L1-L12) in 2007. This information
was not include in the permit application for the previous Part 71 permit, issued
on January 4, 2008. However, the installation of this control equipment
Page 3 of 29
decreases the particulate emissions from these units and is considered a minor
permit modification.
(4)
Add operating limits for auxiliary boilers AUX A and AUX B:
In order to be qualify for “limited-use” units under 40 CFR Part 63, Subpart
DDDDD (National Emission Standards for Hazardous Air Pollutants for
Industrial, Commercial, and Institutional Boilers and Process Heaters), the
permittee requested to include an operating limit of 10% of the annual capacity
into this Part 71 renewal permit for the auxiliary boilers. This Part 71 permit
will also include additional recordkeeping requirements for these auxiliary
boilers. These proposed changes are considered significant permit
modifications.
(5)
Installation of PM CEMS with Boilers U1, U2, U3:
In an addendum to Title V renewal application received on January 21, 2015,
the permittee stated that they plan to comply with the new PM emission limit in
National Emission Standards for Hazardous Air Pollutants: Coal- and Oil-Fired
Electric Utility Steam Generating Units (NESHAP, Subpart UUUUU) using PM
Continuous Emission Monitoring Systems (CEMS). The PM CEMS have been
installed for each of the boilers U1, U2, U3. Since the PM emission limit in this
NESHAP, Subpart UUUUU is most stringent applicable PM emission limit for
boilers U1, U2, and U3, operating PM CEMS according to the NESHAP
requirements exempts the permittee from Continuous Assurance Monitoring
(CAM) requirements (40 CFR Part 64) and the existing CAM requirements for
boilers U1, U2, and U3 in the Part 71 permit could be removed. However, in an
addendum to Title V renewal application received on March 31, 2015, the
permittee stated that PM CEMS are still not operating properly and requested
the existing CAM requirements stayed in the Part 71 renewal permit until such
time the PM CEMS are fully in operation. Incorporating the PM CEM
requirements to the Part 71 permit is considered a significant permit
modification.
The procedure for reviewing this Part 71 renewal permit fulfills the minor permit
modification requirements specified in 40 CFR § 71.7(e)(1) and NNOPR § 405(D), and
the significant permit modification requirements specified in 40 CFR § 71.7(e)(3) and
NNOPR § 405(E).
g. Permitted Emission Units and Control Equipment
Unit ID/
Stack ID
U1/
Stack S1
Unit Description
Maximum
Capacity
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
Page 4 of 29
Commenced
Construction
Date
Control Method
1970
ESP1; FGD system
SCBR1 (1999);
LNB/SOFA*(2011);
Sorbent Injection (2015)
Unit ID/
Stack ID
U2/
Stack S2
\U3/
Stack S3
AUX A
AUX B
CT1
L1 - L12
BC-1 through
BC-4
BC-4A
BFD-5A,
BC-5
BC-6
BC-6A through
BC-6C
BC-7
YSB-1
BC-8A,
BC-8B
BC-8AS,
BC-8BS
PSB-1
BC-9A,
BC-9B
BC-10A,
BC-10B
CC-1A through
CC-9A; CC-1B
through CC-9B
Silos 1A through
1G
Silos 2A through
2G
Silos 3A through
3G
CS
Unloading Bay
A and B
O-LSH-HOP-A
Unit Description
Maximum
Capacity
Commenced
Construction
Date
One (1) pulverized coal-fired boiler,
using No. 2 fuel oil for ignition fuel. Stack S1 is
7,410 MBtu/hr;
1970
equipped with SO2, NOX, CO, and PM CEMS
750 Net MW
and a COMS.
One (1) pulverized coal-fired boiler,
using No. 2 fuel oil for ignition fuel. Stack S1 is
7,410 MBtu/hr;
1970
equipped with SO2, NOX, CO, and PM CEMS
750 Net MW
and a COMS.
One (1) auxiliary boiler;
308 MMBtu/hr
1970
using No. 2 fuel oil as fuel
One (1) auxiliary boiler;
308 MMBtu/hr
1970
using No. 2 fuel oil as fuel
Coal Handling Operations
One (1) railcar unloading operation
10,000 tons/hr
1970
2,400 tons/hr
Twelve (12) hopper feeders
1970
(total)
1,800 tons/hr
Four (4) conveyors to the yard surge bin
1970
(each)
One (1) conveyor to the batch weight system
100 tons/hr
1970
1,800 tons/hr
Two (2) reclaim conveyors
1970
(each)
One (1) conveyor to the yard surge bin
1,500 tons/hr
1970
1,800 tons/hr
Three (3) conveyors to the stacker/reclaimer
1970
(each)
One (1) conveyor to the emergency reclaim
1,500 tons/hr
1970
hopper
One (1) yard surge bin
1,800 tons/hr
1970
1,500 tons/hr
Two (2) conveyors to plant surge bin
1970
(each)
1,500 tons/hr
Two (2) screens
1970
(each)
One (1) plant surge bin
3,000 tons/hr
1970
Two (2) conveyors to the coal silos for boilers
1,500 tons/hr
1970
U1 and U2
(each)
Two (2) conveyors to the coal silos for boiler
1,500 tons/hr
1970
U3
(each)
Three (3) enclosed cascading conveying systems
1,500 tons/hr
to the coal storage silos for boilers U1, U2, and
1970
(each)
U3
3,000 tons/hr
Seven (7) storage silos for boiler U1
1970
(each)
3,000 tons/hr
Seven (7) storage silos for boiler U2
1970
(each)
3,000 tons/hr
Seven (7) storage silos for boiler U3
1970
(each)
3,300 tons/hr
Outdoor coal storage piles
1970
(total)
Limestone Handling System Associated with the FGD Systems
38 tons/hr
Two (2) truck unloading operations
1997
(each)
One (1) limestone unloading hopper
300 tons/hr
1997
Page 5 of 29
Control Method
ESP2; FGD system
SCBR2 (1998);
LNB/SOFA*(2010);
Sorbent Injection (2015)
ESP3; FGD system
SCBR3 (1997);
LNB/SOFA*(2009);
Sorbent Injection (2015)
N/A
N/A
wet suppression
wet suppression
DC-8
DC-8
DC-8
DC-8
wet suppression/
enclosure
wet suppression
DC-8
DC-8
DC-8
DC-5
DC-5
DC-5
DC-1 through DC-4,
DC-6, and DC-7
DC-1, DC-2, and
baghouse PR-1.
DC-3, DC-4, and
baghouse PR-2.
DC-6, DC-7, and
baghouse PR-3.
wet suppression
N/A
DC-9
Unit ID/
Stack ID
O-LSH-HOP-B
O-LSH-FDR-A
O-LSH-FDR-B
O-LSH-CNV-A
O-LSH-CNV-B
O-LSH-SILO-A
and B
O-LSP-FDR-A
and B
O-LSP-CNV-A
and B
O-LSP-MILL-A
and B
LS
Silo 1
Silo 2
Silo 1 and 2
Loading
DWB-A through
DWB-F
Unit Description
One (1) limestone unloading hopper
One (1) conveyor
One (1) conveyor
One (1) conveyor
One (1) conveyor
300 tons/hr
300 tons/hr
300 tons/hr
300 tons/hr
300 tons/hr
300 tons/hr
Two (2) limestone storage silos
(each)
Two (2) enclosed feeders to the slurry
36 tons/hr
preparation system
(each)
5 tons/hr
Two (2) enclosed cleanout conveyors
(each)
36 tons/hr
Two (2) ball mills
(each)
600 tons/hr
Limestone storage piles
(total)
Fly Ash Handling System
One (1) fly ash bin for boilers U1 and U2
46 tons/hr
One (1) fly ash bin for boiler U3
46 tons/hr
Two (2) partially enclosed fly ash truck loading
38 tons/hr
operations
(each)
Six (6) bottom ash truck loading operations.
46 tons/hr
The bottom ash is processed in a wet form
(each)
Soda Ash/Lime Handling Systems
SAB-1A, SAB2A, SAB-1B,
SAB-2B
Four (4) soda ash storage bins
LB-1 and LB-2
Two (2) lime storage bins
PAC Silo A
PAC Silo B
Fugitive-PAC
Fugitive-CaBr2
TR
Maximum
Capacity
Commenced
Construction
Date
1997
1997
1997
1997
1997
0.4 tons/hr
(each)
0.57 tons/hr
(each)
Reagent Handing Systems
Power active carbon (PAC) storage silo
40 tons
PAC storage silo
40 tons
Truck traffic on unpaved roads for PAC delivery
30 VMT/yr**
Truck traffic on unpaved roads for Calcium
365 VMT/yr**
Bromide delivery
Miscellaneous Operations
813,000 gal/min
Six (6) cooling towers
(total)
Fugitive emissions from unpaved roads
N/A
Control Method
DC-10
DC-9
DC-10
DC-9
DC-10
1997
DC-11
1997
N/A
1997
N/A
1997
N/A
1997
wet suppression
1970
1970
DC-S1/2
DC-S3
1970
DC-S1/2 and DC-S3
1970
wet suppression
1970
dust collector BH-6
1970
dust collector BH-7
2015
2015
2015
integral baghouse
integral baghouse
water spray
2015
water spray
1970
N/A
1970
wet suppression
Note: (*) LNB/SOFA = Low-NOX burner (LNB) and Separated Overfire Air (SOFA) system.
(**) VMT = vehicle miles traveled.
h. Unpermitted Emission Units and Control Equipment
No unpermitted emission units were found to be operating at this source during this
review process.
Page 6 of 29
i. New Emission Units and Control Equipment
There is no new emission unit or control equipment proposed during this review process.
j. Insignificant Activities and Emissions
This stationary source also emits air pollutants from insignificant activities and at
insignificant emissions levels, defined in 40 CFR § 71.5(c)(11)(ii) as emissions from an
emissions unit with the potential to emit non-hazardous regulated air pollutants in an
amount less than 2 tons per year or a single HAP in an amount less than 1,000 pounds
per year or the de minimis level established under CAA § 112(g), whichever is less.
These emissions come from the following insignificant activities and emissions units:
(a)
Nine (9) diesel-fired emergency generators, as specified in Table 1 below:
Table 1 – Diesel-Fired Emergency Generators
Unit ID
EG1
Unit Description
EG2
Emergency generator for boilers U1
and U2
Emergency generator for boiler U3
EG3
Warehouse emergency generator
NPG-746
NGS-120A
NPG-529
NPG-384
NPG-811
NPG-818
Emergency generator
Emergency fire pump
Portable generator
Portable generator
Portable generator
Portable generator
Installation
Date
Max. Power
Output (hp)
Type of
Engine*
(CI or SI)
1983
515
CI
1976
Before
4/1/2006
2003
2010
1987
1977
2007
2007
280
CI
70
CI
469
300
335
141
34
717
CI
CI
CI
CI
CI
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
NGS-062A
NGS-063A
NGS-064A
NGS-065A
NGS-067A
NGS-068A
NGS-070A
Type of Liquid
Stored
Diesel
Diesel
Gas
Used Oil
Used Oil
30 Wt Engine Oil
30 Wt Engine Oil
Page 7 of 29
Construction
Date
1991
1991
1991
1991
1991
1991
1991
Max. Capacity
(gallons)
14,000
14,000
12,000
2,500
550
550
550
Unit ID
NGS-071A
NGS-072A
NGS-073A
NGS-074A
NGS-075A
NGS-075B
NGS-076A
NGS-077A
NGS-078A
NGS-079A
NGS-080A
NGS-081A
NGS-082A
NGS-083A
NGS-084A
NGS-085A
NGS-086A
NGS-088A
NGS-090A
NGS-091A
NGS-092A
NGS-093A
NGS-094A
NGS-095A
NGS-096A
NGS-097A
NGS-098A
NGS-099A
NGS-100A
NGS-101A
NGS-102A
NGS-103A
NGS-104A
NGS-106A
NGS-107A
NGS-108A
NGS-109A
NGS-110A
NGS-111A
NGS-112A
NGS-113A
NGS-113B
NGS-113C
NGS-114A
NGS-115A
NGS-116A
NGS-117A
Type of Liquid
Stored
10 Wt Engine Oil
Diesel
Diesel
Diesel
Diesel
Diesel
Clean Lube Oil
Dirty Lube Oil
10 Wt Engine Oil
Mobile Diesel
Mobile Diesel
Mobile Diesel
30 Wt Engine Oil
10 Wt Engine Oil
Mobile Diesel
Mobile Diesel
Mobile Diesel
Mobile Diesel
Turbine Lube Oil
Turbine Lube Oil
Turbine Lube Oil
Turbine Lube Oil
Turbine Lube Oil
Turbine Lube Oil
Turbine Lube Oil
Turbine Lube Oil
Turbine Lube Oil
H2 Seal Oil
H2 Seal Oil
H2 Seal Oil
Transformer Oil
Transformer Oil
Transformer Oil
Diesel
Lube Oil
Diesel
Diesel
Lube Oil
Lube Oil
Lube Oil
Used Diesel
Used Diesel
Used Diesel
Diesel
Diesel
Diesel
Diesel
Page 8 of 29
Construction
Date
1991
1991
1991
1991
1974
2000
1973
1973
1991
Early '70s
Early '70s
Early '70s
1991
1991
Early '70s
1974
1974
1974
1974
1974
1974
1975
1975
1975
1976
1976
1976
1975
1974
1976
1973
1973
1973
1974
1991
1991
1974
1982
1982
1982
2012
2012
2012
2002
Unknown
2002
2003
Max. Capacity
(gallons)
550
2,000
10,000
10,000
5,040,000
172,000
16,000
16,000
550
200
200
200
550
550
200
400
350
400
7,450
650
650
7,450
650
650
7,450
650
650
650
650
650
5,600
5,750
5,750
10,000
750
900
400
300
300
300
500
500
500
100
200
100
500
NGS-118A
NGS-119A
NGS-120A
NGS-121A
NGS-122A
NGS-123A
NGS-124A
NGS-125A
Type of Liquid
Stored
Diesel
Diesel
Diesel
Lube Oil
Diesel
Diesel
Diesel
Diesel
Construction
Date
2003
1991
2010
N/A
2003
2002
N/A
Unknown
NGS-126A
Variouse Oils
2008
NGS-127A
NGS-128A
NGS-129A
NGS-130A
NGS-131
NGS-131A
through 131O
NGS-132A
NGS-133A
NGS-134A
through 134D
NGS-135
Diesel/Unleaded Fuel
Diesel/Unleaded Fuel
Diesel
Diesel
Used Oil for Heating
2005
2005
Unknown
2002
N/A
Used Oil
1991
540 (each)
Diesel
Diesel
2002
2002
100
100
Used Oil
N/A
250 (each)
Used Oil
N/A
100
Unit ID
Max. Capacity
(gallons)
500
150
150
550
500
140
100
200
12 tanks,
\60 gal each
550/100
550/100
200
100
550
(e)
Landscaping, building maintenance, or janitorial activities.
(f)
Hand-held or manually operated equipment used for buffing, polishing,
carving, cutting, drilling, machining, routing, sanding, sawing, surface
grinding, or tuning of precision parts, metals, plastics, masonry, glass, or
wood.
(g)
Equipment used during powder coating operations.
(h)
Lab equipment used exclusively for chemical and physical analyses.
(i)
Equipment used during maintenance painting and surface coating.
(j)
Equipment used during parts cleaning.
(k)
Equipment used during maintenance sand blasting.
(l)
Other emissions units with the potential to emit insignificant levels of
regulated air pollutants or HAPs, as described in Table 3 below:
Page 9 of 29
Table 3 - Other Emissions Units with Insignificant Emissions Levels
Unit Description
Main turbine lube oil reservoir
M T lube oil filter canisters
Aux turbine lube oil reservoir
Electro hydraulic control reservoir
Pulverizer lube oil reservoir
Pulverizer lube oil reservoir
Condensate pump reservoir
Boiler Feed BP oil reservoir
Inst / service air compressor
Soot blowing air compressor
Primary air fan
Induced draft fan
Forced draft fan
Coal belt gear case
Cooling tower circ pump
Cooling fan gear case
Brine concentrator compressor
Brine concentrator compressor
Chrystallizer compressor
Transformer (spare) (mineral oil)
Emergency diesel fire pump
Transformer (main)
Transformer (aux)
Transformer (main station service)
Transformer (main station service)
Reactor tank
Reactor tank
Thyrite varister oil tank
Large capacitor oil tanks
Small capacitor oil tanks
Transformer (50 KV at RR)
Circuit breaker oil tank (230 KV)
Transformer 4,160 V
Transformer 4,160 V
Transformer 480 V
Transformer 480 V
Transformer 480 V
Transformer/rectifier set
Transformer/rectifier set
Transformer/rectifier set
Transformer/rectifier set
Transformer 4,160 V (lake pump)
Transformer 480 V (lake pump)
Waste oil storage tank (cent yard)
Generator, diesel (Generac)
Recycle slurry system gear box
Page 10 of 29
Max. Capacity
(gallons)
7,450
100
650
400
100
300
85
22
50
250
85
110
10
35
10
34
100
150
275
265
250
9,550
6,672
21,980
17,730
5,500
6,142
2,446
3.2
2.8
4,180
2,575
1,409
1,193
268
338
343
165
140
132
117
1,259
160
500
265
16
Number of Units
3
6
2
3
7
14
9
9
9
3
6
12
6
35
6
30
1
2
1
2
1
12
3
1
1
12
12
12
5,581
2,210
3
5
14
2
28
30
5
80
32
64
64
3
2
1
1
12
Unit Description
Recycle slurry system gear box
Oxidation air system oil res.
Recycle valve Hydraulic sys.
Reactivator agitator
Limestone feed tank agitator
Absorber sump agitator
Ball mill gear box
Ball mill lube reservoir tank
Limestone conveyor gear box
Limestone transfer tank agitator
Filtrate raw water tank gear box
Ball mill sump tank agitator
LSP sump agitator
Filtrate transfer tank agitator
Secondary vacuum pump gear box
Absorber holding tank agitator
Bi-product sump agitator
Primary dewatering agitator
Conveyer feedbelt gear box
Antifreeze storage tank (NGS-069A)
Waste antifreeze storage tank (NGS-066A)
Sulfuric acid tank (NGS-201)
Sulfuric acid tank (NGS-202, 203, and 204)
Sulfuric acid tank (NGS-205)
Ammonia tank (NGS-208)
Ferric chloride tank (NGS-209)
Acid or caustic tank (NGS-210 and 211)
Sodium hydroxide tank (NGS-206 and 207)
Sodium hypochlorite tank (NGS-212, 213, and
214)
Scale inhibiter tank (NGS-215 through 220)
Dust Suppressant (Dusbloc) Tank
Dust Suppressant (Dusbloc) Tank
Max. Capacity
(gallons)
22
60
120
13
24
0.75
52
110
39
44
44
7
0.75
24
4.5
23
1.5
2
1.5
550
1,000
20,000
15,000
10,000
10,000
16,000
24,000
10,000
Number of Units
12
9
3
30
3
6
2
2
3
1
1
2
3
1
3
10
2
6
2
1
1
1
3
1
1
1
2
2
4,500
3
2,000
1,000
4,000
6
1
1
k. Enforcement Issue
There are no enforcement actions pending.
l. Emission Calculations
See Appendix A of this document for detailed calculations (pages 1 through 16).
m. Potential to Emit
Potential to emit (PTE) means the maximum capacity to emit any CAA-regulated air
pollutant under the facility’s physical and operational design. Any physical or
Page 11 of 29
operational limitation on the maximum capacity of this facility to emit an air pollutant,
including air pollution control equipment and restrictions on hours of operation or on
the type or amount of material combusted, stored, or processed, may be treated as a part
of its design if the limitation is enforceable by US EPA or NNEPA. Actual emissions
are typically lower than PTE.
Potential to Emit
(tons/year)
Process/facility
Boiler U1
PM
1,947
PM10
1,097
PM2.5
488
SO2
3,246
NOx
7,789
VOC
75.3
CO
4,868
HAPs
22.7
Boiler U2
Boiler U3
Auxiliary
Boilers
Coal Handling
Coal Piles
(Fugitive)
Limestone
Handling
Limestone Piles
(Fugitive)
Fly Ash
Handling
Soda Ash/Lime
Handling
Cooling Towers
PAC Storage
Silos
Unpaved Roads
associated with
PAC and CaBr2
Delivery
Unpaved Roads
(Fugitive)
Emergency
Generators
(Insignificant)
Other
Insignificant
Activities*
PTE of the
Entire Source
1,947
1,947
1,097
1,097
488
488
3,246
3,246
7,789
7,789
75.3
75.3
4,868
4,868
22.7
22.7
3.92
1.96
0.49
13.9
47.1
0.39
9.81
1.19
5.91
3.41
2.51
-
-
-
-
-
5.43
2.57
0.39
-
-
-
-
-
4.61
2.98
2.98
-
-
-
-
-
4.60
2.17
0.33
-
-
-
-
-
29.2
29.2
29.2
-
-
-
-
0.01
0.26
0.26
0.26
-
-
-
-
-
19.2
19.2
19.2
-
-
-
-
-
0.90
0.90
0.90
-
-
-
-
-
1.28
0.33
0.03
-
-
-
-
-
546
141
14.1
-
-
-
-
-
1.57
1.57
1.57
1.47
22.2
1.77
4.78
Negligible
15.3
15.3
15.3
-
-
Less than
5.00
-
Negligible
6,481
3,513
1,550
9,752
23,437
233
14,620
69.3
100
10 for a
single HAP
and 25 for
total HAPs
Title V Major
Source
Thresholds
NA
100
100
100
100
100
*Note: This is an estimate on the PM/PM10/PM2.5 emissions from the welding and blasting operations, and VOC/HAP emissions
from the parts cleaning, surface coating operations, and the storage tanks.
(a)
The potential to emit of PM10, PM2.5, SO2, VOC, CO and NOx are equal to or
greater than 100 tons per year. In addition, the potential to emit of HAPs from
Page 12 of 29
this source is greater than 10 tons per year of a single HAP and greater than 25
tons per year of total HAPs. Therefore, this source is considered a major source
under 40 CFR § 71.2 (defining “major source” for purposes of the Federal
Operating Permit Program).
(b)
n.
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.
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
PM10
SO2
VOC
NOx
Hydrogen Chloride
Hydrogen Fluoride
Greenhouse Gas (GHG)
2.
Actual Emissions (tons/year)
432
4,404
200
16,276
6.0
9.0
17,022,237
Tribe Information
a.
General
The Navajo Nation has the largest land base of any tribe in the country, covering more
than 27,000 square miles in three states: Arizona, Utah, and New Mexico. The Navajo
Nation currently is home to more than 260,000 people. Industries on the Navajo Nation
include oil and natural gas production, coal and uranium mining, electric generation and
distribution, and tourism.
b.
Local air quality and attainment status
All areas of the Navajo Nation are currently designated as attainment or unclassifiable
for all pollutants for which a National Ambient Air Quality Standard (NAAQS) has
been established.
Page 13 of 29
3.
Prevention of Significant Deterioration (PSD) Applicability
This source is in one of the 28 source categories listed in 40 CFR § 52.21(b)(1)(i)(a) and has
potential to emit PM and all relevant criteria pollutants greater than 100 tons per year.
Therefore, this source is considered an existing PSD major source. This source commenced
construction in 1970 and commenced modifications in 1997 (installation of the FGD
systems) and 2008 (installation of LBN/SOFA systems). The construction of this source
predated the PSD applicability date of June 1, 1975. Therefore, this source was not required
to obtain a preconstruction permit when it was constructed in 1970. The modifications in
1997 (installation of the FGD systems) did not result in an emissions increase above the PSD
significance thresholds in 40 CFR § 52.21. Therefore, the modification that commenced in
1997 did not trigger PSD.
A PSD permit was issued to this source on July 3, 2008 for the installation of LNB/SOFA
systems for the existing three boilers U1 through U3. An amendment to this PSD permit was
issued on February 8, 2012. According to the requirements in the amended PSD permit, the
permittee is required to comply with the following emission limits for each of the boilers U1
through U3:
(a)
(b)
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.
NOx emissions shall not exceed 0.24 lb/MMBtu based on a 30-day rolling average.
In addition, the permittee is required to install CO CEMS (Continuous Emissions Monitoring
System) to demonstrate compliance with the CO emission limits specified in the PSD
permits.
The above emission limits and the associated compliance monitoring, recordkeeping, and
reporting requirements have been included in this Part 71 permit renewal.
4.
Federal Rule Applicability
(a)
This source is subject to the source-specific Federal Implementation Plan (FIP) for
Navajo Generating Station, Navajo Nation (40 CFR § 49.5513) which was
promulgated on March 5, 2010 and later amended on August 8, 2014 to incorporate
the Regional Haze Best Available Retrofit Technology (BART) requirements.
Pursuant to 40 CFR § 49.5513(d), the permittee shall comply with the following
emission limits on a plant-wide basis:
(1)
The SO2 emissions shall not exceed 1.0 lb/MMBtu averaged over any threehour period;
Page 14 of 29
(2)
The PM emissions shall not exceed 0.06 lb/MMBtu as averaged from at least
three sampling runs per stack, each at a minimum of 60 minutes in duration
and collecting a minimum sample of 30 dry standard cubic feet;
For the stacks of Units U1, U2, and U3, opacity shall not exceed 20% averaged over a
6 minute period, excluding condensed water droplets, or 40% averaged over 6 minutes
during absorber upset transition periods, pursuant to 40 CFR § 49.5513(d)(4).
For dust emissions associated with coal transfer and storage and other dust-generating
activities, opacity shall not exceed 20%, as determined using 40 CFR Part 60,
Appendix A-4, Method 9. The permittee is required to operate and maintain the
existing dust suppression methods for controlling dust from the coal handling and
storage facilities. A dust control plan was submitted by the permittee on June 4, 2010
and a revised plan was received on February 2, 2015. The revised dust control plan is
included in this Part 71 permit renewal as Attachment A.
The permittee shall also comply with the testing, monitoring, reporting, and
recordkeeping requirements specified in 40 CFR § 49.5513(e) and (f).
This FIP was amended on August 8, 2014 to include BART requirements (effective
October 7, 2014). Pursuant to 40 CFR § 49.5513(j)(3), total cumulative NOX
emissions from Units 1, 2, and 3, from January 1, 2009 to December 31, 2044 shall
not exceed the 2009-2044 NOX Cap (494,899 tons). Compliance with this NOx
emission limit must be demonstrated by the operation of the existing NOX CEMS.
The applicable operating, maintenance, recordkeeping, and reporting requirements
for the NOx CEMS specified in the FIP have been incorporated into this Part 71
permit.
This FIP also requires the source to select and implement one of four operating
scenarios listed under 40 CFR § 49.5513(j)(3)(i) to ensure compliance with the NOX
emission cap limit. However, pursuant to 40 CFR § 49.5513(j)(4)(i), the permittee
has until December 1, 2019 to notify U.S. EPA of its choice of operating scenario.
Therefore, the requirements associated with these four operating scenarios are not
included in this Part 71 permit. Pursuant to 40 CFR § 49.5513(j)(4)(iii), the source is
required to submit a permit revision application no later than December 31, 2020 to
incorporate the specific requirements, including compliance monitoring,
recordkeeping, and reporting requirements, associated with the selected operating
scenario.
(b)
The existing boilers U1 through U3 are considered utility units under the definition of
40 CFR § 72.2. Therefore, these boilers are subject to the Acid Rain Program
requirements (40 CFR Part 72 through 40 CFR Part 78), pursuant to 40 CFR §
72.6(a)(3). An Acid Rain Renewal Application was received on June 19, 2013 and the
renewal of the acid rain permit will be issued with this Part 71 permit renewal.
Pursuant to 40 CFR § 72.9, the permittee shall comply with the following:
Page 15 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
SO2 Allowance for years
Unit
2010 and beyond (tons/yr)
Boiler U1
24,949
Boiler U2
23,354
Boiler U3
23,693
Facility Total
71,996
Beginning in 2007, the SO2 allowance allocations apply to the entire facility,
instead of each individual emission unit at this facility.
(3)
Acid rain emissions limitations for nitrogen oxides in 40 CFR Part 76 for coalfired boilers. Beginning in calendar year 2008, the permittee shall comply with
the NOx emission limit of 0.40 lbs/MMBtu for each of the boilers U1, U2, and
U3, pursuant to 40 CFR § 76.7(a)(1).
(c)
40 CFR § 52.145(d) (Visibility Protection) includes the following specific
requirements for the three (3) coal-fired boilers at Navajo Generating Station: (1)
Pursuant to 40 CFR § 52.145(d)(2), the SO2 emissions from each of the coal fired
boilers (boilers U1, U2, and U3) shall not exceed 42 ng/J (0.1 lbs/MMBtu) heat input;
and (2) Pursuant to 40 CFR § 52.145(d)(3), compliance with the emission limit shall
be determined daily on a plant-wide rolling annual basis.
(d)
This source is subject to the Regional Haze Rule (40 CFR § 51.308) because it is a
BART-eligible source (that is, a fossil-fuel fired steam electric plant of more than 250
MMBtu/hr heat input which was not in operation prior to August 7, 1962, was in
existence on August 7, 1977, and has the potential to emit greater than 250 tons per
year of any air pollutant, see 40 CFR § 51.301) that may reasonably be anticipated to
cause or contribute to any impairment of visibility in a mandatory Class I area.
Pursuant to 40 CFR § 51.308(e), States are required to submit implementation plans
that, among other measures, contain either emission limits representing Best Available
Retrofit Technology (BART) for BART-eligible sources that may reasonably be
anticipated to cause or contribute to any impairment of visibility in any mandatory
Class I area, or alternative measures that provide for greater reasonable progress than
BART. Under the Clean Air Act, 42 USC § 7601(d), and the Tribal Authority Rule, 40
CFR § 49.11(a), EPA may promulgate a federal implementation plan in the absence of
a tribal implementation plan. Under this authority, EPA promulgated a source-specific
Page 16 of 29
FIP containing BART requirements for this source; the FIP is codified at 40 CFR §
49.5513(j).
(e)
The Clean Air Mercury Rule (CAMR, CAA § 112(n)) was promulgated on May 18,
2005 and was developed to permanently cap and reduce the mercury (Hg) emissions
from coal-fired power plants. However, on February 8, 2008, the U.S. Court of
Appeals for the District of Columbia Circuit issued a decision that vacated the Clean
Air Mercury Rule. See New Jersey v. EPA, 517 F.3d 574 (D.C. Cir. 2008). Therefore,
CAMR requirements are not included in this Part 71 permit renewal. However,
mercury emissions from utility power plants are regulated under 40 CFR Part 63,
Subpart UUUUU (see below for discussion of applicable 40 CFR Part 63, Subpart
UUUUU requirements).
(f)
This existing source is a major source for HAPs. The three boilers at this source (U1
through U3) are considered existing coal-fired electric generating units (EGUs) and
are subject to National Emission Standards for Hazardous Air Pollutants: Coal- and
Oil-Fired Electric Utility Steam Generating Units (40 CFR Part 63, Subpart UUUUU),
which were promulgated on February 16, 2012 and later revised on November 19,
2014.
Pursuant to 40 CFR § 63.9984(b), facilities subject to subpart UUUUU must comply
with the requirements of this NESHAP by April 16, 2015, unless they receive approval
for an extension to the compliance date under 40 CFR § 63.6(i). The permittee
requested an extension on the compliance date for the mercury provisions of this
NESHAP due to the technical difficulties associated with installing add-on mercury
controls. This extension request was granted by U.S. EPA and NNEPA on January 27,
2014. The extended compliance date for the mercury provisions is April 16, 2016. The
source must also comply with the following implementation schedule included in the
extension approval letter:
(1)
By April 1, 2015, submit to NNEPA a title V permit modification application
that incorporates the final mercury control strategy. [Note: This permit
modification application was received on March 31, 2015]
(2)
By October 1, 2015, commence construction to incorporate the mercury
control strategy on-site.
(3)
By April 16, 2016, complete on-site construction and comply with all mercury
provisions of this NESHAP.
The permitee is also required to submit interim progress reports and a final report to
NNEPA and U.S. EPA.
The permittee shall comply with the following emission limits, pursuant to 40 CFR §
63.9991(a) and Table 2 of this NESHAP:
Page 17 of 29
(1)
By April 16, 2015, filterable PM emissions shall not exceed 0.03 lb/MMBtu or
0.3 lb/MWh.
(2)
By April 16, 2015, SO2 emissions shall not exceed 0.2 lb/MMBtu or 1.5
lb/MWh.
(3)
By April 16, 2016, Mercury (Hg) emissions shall not exceed 1.2 lb/TBtu or
0.013 lb/GWh.
The permitttee plans to use a combination of calcium bromide application and
powdered active carbon (PAC) injection system to control the Hg emissions from the
existing coal-fired boilers. Implementation of these control technologies will require
the installation of calcium bromide and PAC storage and handling equipment. The
construction and operation of this Hg control system is permitted under Tribal Minor
NSR Permit #T-0004-NN, issued on August 26, 2015.
In the permit application submitted on March 31, 2015, the permittee stated that they
will demonstrate compliance with the SO2 emission limit in this NESHAP using
CEMS and demonstrate compliance with the Hg emission limit using sorbent trap
monitoring system for each stack. The permittee plans to use PM CEMS to show
compliance with the filterable PM emissions limit under this NESHAP. However, the
newly installed PM CEMS are not currently working properly. The permittee
requested to conduct quarterly PM performance stack testing to show compliance with
the PM emission limit until such time the PM CEMS operate properly, which is
expected to occur in late 2015.
The associated compliance, monitoring, testing, notification, recordkeeping, and
reporting requirements are included in the permit as Attachment C. Please note that the
requirements pertaining to Hg emissions are not applicable until April 16, 2016.
(g)
Each of the boilers at this source (U1 through U3, AUXA, and AUXB) has a
maximum heat input greater than 250 MMBtu/hr. However, these boilers commenced
construction before August 17, 1971 and the permittee stated that no modification or
reconstruction to the boilers has occured since the construction of these boilers.
Therefore, the New Source Performance Standards (NSPS) for Fossil-Fuel-Fired
Steam Generators (40 CFR Part 60, Subpart D), which apply to generators that
commenced construction or modification after August 17, 1971, are not applicable to
the boilers at this source.
(h)
This existing source is a major source for HAPs. Boilers U1 throught U3 are subject
to NESHAP for Coal- and Oil-Fired Electric Utility Steam Generating Units (40 CFR
Part 63, Subpart UUUUU). Therefore, these three boilers are not subject to the
National Emission Standards for Hazardous Air Pollutants for Industrial,
Commercial, and Institutional Boilers and Process Heaters (40 CFR Part 63, Subpart
DDDDD), pursuant to 40 CFR § 63.7491(a). However, the No. 2 fuel oil-fired
auxiliary boilers (AUX A and AUX B) are subject to this NESHAP. According to the
Page 18 of 29
initial notification submitted by the permittee on May 30, 2013, the auxiliary boilers
operate less than 10% of the annual capacity and are considered “limited-use” units,
as defined in 40 CFR § 63.7575.
Pursuant to 40 CFR § 63.7500(c), limited-use boilers are only required to complete a
tune-up every 5 years. There are no specific emission limits, energy assessment, or
operating limits for these type of boilers. Pursuant to 40 CFR § 63.7495(b), the
compliance date for the existing affected units is January 31, 2016.
In addition, 40 CFR § 63.7555(d)(3) requires the permitting authority to include a
federally enforceable condition in the permittee’s Part 71 permit to limit the operation
of the auxiliar boilers (AUX A and AUX B) to not more than 10% of the annual
capacity for each unit, in order to ensure they continue to qualify for “limited-use”
unit status. The permittee has requested the inclusion of this opertating limit in the
Part 71 renewal permit.
(i)
The coal handling operations at this source process more than 200 tons of coal per
day. However, all of the coal handling operations at this source commenced
construction before October 24, 1974 and the permittee stated that no modification to
the coal handling operations has occured since the construction of these units.
Therefore, pursuant to 40 CFR § 60.250, the requirements of the New Source
Performance Standards for Coal Preparation and Processing Plants (40 CFR Part 60,
Subpart Y) are not applicable.
(j)
Lime is considered a nonmetallic mineral as defined in 40 CFR § 60.671. The
limestone handling system at this source commenced construction after August 31,
1983 and performs grinding operations. Therefore, pursuant to 40 CFR § 60.670, the
limestone handling system at this source is subject to the requirements of the New
Source Performance Standards (NSPS) for Nonmetallic Mineral Processing Plants
(40 CFR Part 60, Subpart OOO). The affected facilities include each grinding mill,
screening operation, belt conveyor, storage bin, and enclosed truck loading station
associated with the limestone handling system.
Pursuant to 40 CFR § 60.672, the permittee shall comply with the following emission
limitations:
(1)
Emissions from any stack shall not exceed a PM limit of 0.05 g/dscm (0.022
gr/dscf) and an opacity limit of 7%.
(2)
Fugitive emissions shall not exceed 10% opacity, except for crushers at which
a capture system is not used.
(3)
Fugitive emissions from crushers at which a capture system is not used shall
not exceed 15% opacity.
Page 19 of 29
(4)
Truck dumping of nonmetallic minerals into any screening operation, feed
hopper, or crusher is exempt from the requirements of 40 CFR § 60.672.
(5)
If an affected facility is enclosed in a building, then each enclosed affected
facility must comply with the emission limits specified above, or the building
enclosing any affected facility shall not emit any fugitive emissions exceeding
7% opacity or any emissions from a vent exceeding a PM limit of 0.05 g/dscm
(0.022 gr/dscf).
(6)
Stack emissions from any baghouse that controls emissions from only an
individual, enclosed storage bin shall not exceed 7 percent opacity.
The permittee shall also comply with the testing requirements in 40 CFR § 60.675
and the recordkeeping and reporting requirements in 40 CFR § 60.676.
(k)
The emergency fire pump (NGS-120A) was manufactured as a certified National Fire
Protection Association (NFPA) fire pump engine after July 1, 2006. Therefore, this
unit is subject to the requirements of the New Source Performance Standards for
Stationary Compression Ignition Internal Combustion Engines (40 CFR Part 60,
Subpart IIII), pursuant to 40 CFR § 60.4200(a)(2)(ii). All other emergency generators
at this facility are not subject to these NSPS because they were either installed before
April 1, 2006 or are not stationary units.
The emergency fire pump (NGS-120A) has a maximum capacity of 300 hp and was
manufactured in 2010. The emissions from this unit shall comply with the following
emission limits, pursuant to 40 CFR § 60.4205(c) and Table 4 of these NSPS:
(1)
NMHC + NOX emissions shall not exceed 4.0 g/KW-hr or 3.0 g/HP-hr.
(2)
PM emissions shall not exceed 0.2 g/KW-hr or 0.15 g/HP-hr.
Engine NGS-120A has a displacement less than 9 liters per cylinder. Pursuant to 40
CFR § 60.4207(b), the permittee must use diesel fuel that meets the requirements of
40 CFR § 80.510(b) for nonroad diesel fuel (ultra low sulfur diesel fuel), except that
any existing diesel fuel purchased (or otherwise obtained) prior to October 1, 2010,
may be used until depleted.
The permittee shall comply with the operating requirements specified 40 CFR §
60.4211(a) and the engine certification requirements in 40 CFR § 60.4211(c). There
are no initial notification requirements for this emergency fire pump, pursuant to 40
CFR § 60.4214(b).
(l)
The emergency generators and fire pumps at this source are considered stationary
reciprocating internal combustion engines (RICE) and are subject to the NESHAP for
Stationary Reciprocating Internal Combustion Engines (40 CFR Part 63, Subpart
Page 20 of 29
ZZZZ). Stationary diesel generators EG1, EG2, EG3, NPG-746, and NGS-120A are
subject to this NESHAP. All the affected units are compression ignition engines (CI).
The applicable requirements for the affected units can be divided into the following
three categories:
(1) Units with no specific requirements:
For the existing emergency generators with capacities greater than 500 hp (EG1), the
permittee is not required to meet the requirements of this subpart and of 40 CFR 63,
Subpart A, pursuant to 40 CFR § 63.6590(b)(3)(iv). No initial notification is required.
(2) Units with specific requirements:
For the existing emergency generators with capacities equal to or less than 500 hp
(EG2, EG3, and NPG-746), the permittee shall comply with the following work
practice requirements specified in Table 2c of this subpart, pursuant to 40 CFR §
63.6602:
(1)
Change oil and filter every 500 hours or annually;
(2)
Inspect air cleaner every 1,000 hours or annually;
(3)
Inspect hoses and belts every 500 hours or annually; and
(4)
Minimize the engine's time spent at idle and minimize the engine's startup
time to a period needed for appropriate and safe loading of the engine, not to
exceed 30 minutes, after which time the non-startup emission limitations
apply.
The initial compliance date for units EG2, EG3, and NPG-746 is May 3, 2013,
pursuant to 40 CFR § 63.6595(a).
(3) Units subjected to NSPS under 40 CFR Part 60, Subpart IIII:
The emergency fire pump (NGS-120A) is an emergency unit with a maximum
capacity less than 500 hp and is subject to the requirements of NSPS for Stationary CI
ICE, 40 CFR Part 60, Subpart IIII. For this unit, compliance with this NESHAP is
demonstrated by complying with the requirements specified in the NSPS for
Stationary CI ICE, 40 CFR Part 60, Subpart IIII, pursuant to 40 CFR § 63.6590(c).
The following table summarizes the capacity, construction date, unit category type,
and applicable requirements for each emergency generator subject to 40 CFR Part 63,
Subpart ZZZZ:
Page 21 of 29
Unit ID
EG1
EG2
EG3
NPG-746
NGS-120A
Max. Capacity
(hp)
515
280
70
469
300
Construction Date
before 12/19/2002
before 06/12/2006
before 06/12/2006
before 06/12/2006
after 06/12/2006
Unit Category
Existing RICE
Existing RICE
Existing RICE
Existing RICE
New RICE
Subpart ZZZZ
Requirements
None
Work Practice
Work Practice
Work Practice
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 0801, issued on November 20, 2008, require the source to install and operate CEMS to
ensure continuous compliance with the SO2, NOX, and CO emission limits. These
requirements have been incorporated into this part 71 renewal permit. Therefore, the
SO2, NOx, and CO emissions from boilers U1 through U3 are exempt from the
requirements of 40 CFR Part 64 (Compliance Assurance Monitoring (CAM)),
pursuant to 40 CFR § 64.2(b)(1)(vi).
Page 22 of 29
The FIP for this source (40 CFR § 49.5513) has specific PM emission limits for boilers
U1 through U3 and the CAM requirements used to apply to these units. However, the
permittee recently installed PM CEMS for each of the boilers U1, U2, and U3 to
demonstrate compliance with the PM emission limits specified in NESHAP, Subpart
UUUUU. Since the PM emission limit in this NESHAP is more stringent than the PM
emission limits in FIP, compliance with the PM emission limit for NESHAP, Subpart
UUUUU using the new PM CEMS is sufficient to demonstrate compliance with PM
emission limit in FIP. Therefore, the PM emissions from boilers U1 through U3 are
exempt from the CAM requirements, pursuant to 40 CFR § 64.2(b)(1)(vi). A permit
condition (Condition II.N) has been added to this Part 71 permit renewal to require the
operation of PM CEMS with the stacks associated with boilers U1, U2, and U3.
However, in an addendum to Title V renewal application received on March 31, 2015,
the permittee stated that PM CEMS are still not operating properly and requested the
existing CAM requirements stayed in the Part 71 renewal permit until such time the
PM CEMS are fully in operation. Therefore, the CAM requirements from the current
Part 71 permit are still included in the renewal permit. The CAM requirements
(included as Condition II.N of the renewal permit) are summarized in the table below
and will still apply until such time the PM CEMS operate properly:
Electrostatic
Precipitator
Indicator
Measurement
Approach
Indicator
Threshold
Wet Limestone
Scrubber
Number of
chambers/fields in
service
The number of
chambers/fields in
service is monitored
and logged on a
continuous basis.
Number of Spray
levels in service
An excursion is
defined as follows:
When an ESP unit is
operating with more
than 3 chambers (18
fields) out of service
during normal
operation of the
boiler.
An excursion is
defined as follows:
When a ESP unit is
operating with more
than one chamber (6
fields) out of service
and less than 2 spray
levels are operating in
the wet limestone
scrubber associated
with the same boiler,
during normal
operations of the
boiler.
The number of wet
limestone scrubber
spray levels in service
is monitored on a
continuous basis.
Page 23 of 29
Wet Limestone
Scrubber
Wet limestone
scrubber exhaust
temperature
The wet
limestone
scrubber exhaust
temperatures are
monitored at the
absorber outlets
prior to the stack
using a J-type
thermocouple.
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.
Wet Limestone
Scrubber
Wet limestone
scrubber on/off
The wet limestone
scrubber on/off
signal is monitored
on a continuous
basis.
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.
Electrostatic
Precipitator
Performance
Criteria
Verification
of
Operational
Status
QA/QC
Indicator
Threshold
Wet Limestone
Scrubber
Wet Limestone
Scrubber
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.
Not Applicable
Not Applicable
Not Applicable
Not Applicable
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 wet limestone
scrubber on/off
signal will undergo
an annual
verification check.
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.
Continuous
An excursion is
defined as follows:
When a ESP unit is
operating with more
than one chamber (6
fields) out of service
and less than 2 spray
levels are operating in
the wet limestone
scrubber associated
with the same boiler,
during normal
operations of the
boiler.
Continuous
The
thermocouple
will undergo a
quarterly
verification check
using a standard
temperature
indicator.
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.
The wet limestone
scrubber on/off
signal is monitored
continuously.
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 is
measured
continuously.
The wet limestone
scrubber exhaust
temperature will be
recorded as an
hourly average by a
data acquisition
handling system.
Monitoring
Frequency
Data
Collection
Procedures
Wet Limestone
Scrubber
Page 24 of 29
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.
The wet limestone
scrubber on/off
signal will be
recorded on a
continuous basis
by the data
acquisition
handling system.
Electrostatic
Precipitator
Averaging
Period
Not Applicable
Wet Limestone
Scrubber
Not Applicable
Wet Limestone
Scrubber
1-Hour average
Wet Limestone
Scrubber
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
Federal Implementation Plan for NGS (40 CFR §
49.5513)
Acid Rain Regulations (40 CFR Parts 72-78)
CAM Requirements (40 CFR Part 64)
Visibility FIP (40 CFR § 52.145(d))
NSPS for Nonmetallic Mineral Processing Plants (40
CFR Part 60, Subpart OOO)
NSPS for Stationary Compression Ignition Internal
Combustion Engines (40 CFR Part 60, Subpart IIII)
NESHAP for Coal- and Oil-Fired Electric Utility
Steam Generating Units (40 CFR Part 63, Subpart
UUUUU)
NESHAP for Industrial, Commercial, and Institutional
Boilers and Process Heaters (40 CFR 63, Subpart
DDDDD)
NESHAP for Stationary Reciprocating Internal
Combustion Engines (40 CFR Part 63, Subpart ZZZZ)
Asbestos NESHAP (40 CFR Part 61, Subpart M)
Page 25 of 29
Current or Future
Requirement
Current
Current
Current
(until PM CEMS operate properly)
Current
Current
Current
Current
Current
Current
Current
Federal Air Quality Requirement
Protection of Stratospheric Ozone (40 CFR Part 82)
Regional Haze BART Requirements (40 CFR §
51.308)
5.
Current or Future
Requirement
Current
Current
(Included in the NGS FIP)
Additional Requirement
(a)
(b)
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.
Pursuant to Tribal Minor NSR Permit #T-0004-NN, issued on August 26, 2015, the
permittee shall comply with the following requirements for the new mercury emission
control system (including a new powdered activated carbon (PAC) injection system
and a new calcium bromide application system):
(1)
Vehicle miles travel (VMT) for truck traffic associated with the delivery of
Page 26 of 29
PAC shall not exceed 30 VMT per 12-month period.
6.
(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.
Endangered Species Act
Pursuant to Section 7 of the Endangered Species Act (ESA), 16 U.S.C. § 1536, and its
implementing regulations at 50 CFR Part 402, USEPA is required to ensure that any action
authorized, funded, or carried out by USEPA is not likely to jeopardize the continued existence
of any Federally-listed endangered species or threatened species or result in the destruction or
adverse modification of such species’ designated critical habitat. NNEPA is issuing this federal
Part 71 permit pursuant to a delegation from USEPA. However, this permit does not authorize
the construction of new emission units or emission increases from existing units, nor does it
otherwise authorize any other physical modifications to the facility or its operations. Therefore,
NNEPA and USEPA have concluded that the issuance of this permit will have no effect on listed
species or their critical habitat.
7.
Use of All Credible Evidence
Determinations of deviations from, continuous or intermittent compliance with, or violations of
the permit are not limited to the testing or monitoring methods required by the underlying
regulations or this permit; other credible evidence (including any evidence admissible under the
Federal Rules of Evidence) must be considered by the source, NNEPA, and U.S. EPA in such
determinations.
8.
NNEPA Authority
Authority to administer the Part 71 Permit Program was delegated to the Navajo Nation EPA
by USEPA Region IX in part on October 13, 2004 and in whole on March 21, 2006. This
permit is issued pursuant to the May 2005 Voluntary Compliance Agreement between the
Page 27 of 29
permittee and the Navajo Nation, which provided for Navajo regulation of NGS for CAA
purposes. The permittee shall comply with the terms of this permit and shall be subject to
enforcement of the permit by the Navajo Nation EPA and USEPA, pursuant to the terms of the
Voluntary Compliance Agreement. The permittee’s agreement to comply is effective upon the
permittee’s written acceptance of the permit and expires at the end of the permit term, unless
the permit is renewed. The permittee’s agreement to comply may be withdrawn during the
permit term only if the Voluntary Compliance Agreement is terminated or expires as provided
in that Agreement.
9.
Public Participation
a. Public Notice
As required by NNOPR § 403(A), this permit renewal is being publicly noticed and
made available for public comment. The content, methods, and timing of public notice
are described in NNOPR § 403(B)-(D), and include a 30- day public comment period.
See also 40 CFR § 71.11(d) (equivalent public notice and comment provisions).
Public notice of this proposed permit action will be provided by mailing a copy of the
notice to the permittee, U.S. EPA Region 9, and the affected states (Utah and Arizona).
A copy of the notice will also be provided to all persons who submit a written request
to be included on the mailing list to the following individual:
Tennille Begay
Navajo Nation Operating Permit Program
P.O. Box 529
Fort Defiance, AZ 86504
E-mail: [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
Fort Defiance, AZ 86504
Copies of the draft permit and this statement of basis can also be obtained free of
charge from NNEPA’s website:
Page 28 of 29
www.navajonationepa.org/airqty/permits
or by contacting Tennille Begay at the NNAQCP address listed above or by telephone
at (928) 729-4248. All documents will be available for review at the NNAQCP office
indicated above during regular business hours.
If you have comments on the draft permit, you must submit them during the 30-day
public comment period. All comments received during the public comment period and
all comments made at any public hearing will be considered in arriving at a final
decision on the permit. The final permit is a public record that can be obtained by
request. A statement of reasons for any changes made to the draft permit and responses
to comments received will be sent to persons who commented on the draft permit.
If you believe that any condition of the draft permit is inappropriate, you must raise all
reasonably ascertainable issues and submit all arguments supporting your position by
the end of the comment period. Any supporting documents must be included in full and
may not be incorporated by reference, unless they are already part of the administrative
record for this permit or consist of tribal, state or federal statutes or regulations or other
generally available referenced materials.
Any comments on the acid rain permit shall be submitted to US EPA at the following
address:
EPA Region 9
75 Hawthorne Street
San Francisco, CA 94105
E-mail: [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.
Page 29 of 29
Page 1 of 16 SOB App A
Appendix A: Emission Calculations
Criteria Pollutant Emissions from
the Coal Fired Boiler U1
Company Name:
Address:
Permit No.:
Reviewer:
Date:
Navajo Generating Station
5 miles east of Page, off U.S. Highway 98, Page, AZ 86040
NN-OP-15-06
ERG/YC
September 4, 2015
Max. Heat Input Capacity
MMBtu/hr
7,410
Ash Content (A)
13.5
% (provided by the source)
PMa
Emission Factor
Potential to Emit in (tons/yr)
Pollutant
PM10b
PM2.5b
SO2c
NOXd
VOCe
COd
0.06
0.729
(0.054A)
0.324
(0.024A)
0.10
0.24
0.05
0.15
(lbs/MMBtu)
(lbs/ton)
(lbs/ton)
(lbs/MMBtu)
(lbs/MMBtu)
(lbs/ton)
(lbs/MMBtu)
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).
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).
b
d
The NOX and CO emission factors are based on the emission limits in the PSD Permit AZ 08-01A, issued on 2/8/12.
e
VOC emission factor is from AP-42, Tables 1.1-19 (09/98).
The heating value of the coal used at this plant is 21.562 MMBtu/ton, provided by the source.
Methodology
PTE of PM10, PM2.5, and VOC (tons/yr) = Max. Heat Input (MMBtu/hr) / 21.562 MMBtu/ton x Emission Factor (lbs/ton) x 8760 hrs/yr x 1 ton/2,000 lbs
PTE of PM, SO2, NOx and CO (tons/yr) = Max. Heat Input (MMBtu/hr) x Emission Factor (lbs/MMBtu) x 8760 hr/yr x 1 ton/2,000 lbs
Page 2 of 16 SOB App A
Appendix A: Emission Calculations
Criteria Pollutant Emissions from
the Coal Fired Boiler U2
Company Name:
Address:
Permit No.:
Reviewer:
Date:
Navajo Generating Station
5 miles east of Page, off U.S. Highway 98, Page, AZ 86040
NN-OP-15-06
ERG/YC
September 4, 2015
Max. Heat Input Capacity
MMBtu/hr
7,410
Ash Content (A)
13.5
% (provided by the source)
Pollutant
PM10b
PM2.5b
SO2c
NOXd
VOCe
COd
0.06
0.729
(0.054A)
0.324
(0.024A)
0.10
0.24
0.05
0.15
(lbs/MMBtu)
(lbs/ton)
(lbs/ton)
(lbs/MMBtu)
(lbs/MMBtu)
(lbs/ton)
(lbs/MMBtu)
1,947
1,097
488
3,246
7,789
75.3
4,868
PMa
Emission Factor
Potential to Emit in (tons/yr)
a
PM emission factor is the emission limit in 40 CFR 49.5513(d)(2).
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).
b
d
The NOX and CO emission factors are based on the emission limits in the PSD Permit AZ 08-01A, issued on 2/8/12.
e
VOC emission factor is from AP-42, Tables 1.1-19 (09/98).
The heating value of the coal used at this plant is 21.562 MMBtu/ton, provided by the source.
Methodology
PTE of PM10, PM2.5, and VOC (tons/yr) = Max. Heat Input (MMBtu/hr) / 21.562 MMBtu/ton x Emission Factor (lbs/ton) x 8760 hrs/yr x 1 ton/2,000 lbs
PTE of PM, SO2, NOx and CO (tons/yr) = Max. Heat Input (MMBtu/hr) x Emission Factor (lbs/MMBtu) x 8760 hr/yr x 1 ton/2,000 lbs
Page 3 of 16 SOB App A
Appendix A: Emission Calculations
Criteria Pollutant Emissions from
the Coal Fired Boiler U3
Company Name:
Address:
Permit No.:
Reviewer:
Date:
Navajo Generating Station
5 miles east of Page, off U.S. Highway 98, Page, AZ 86040
NN-OP-15-06
ERG/YC
September 4, 2015
Max. Heat Input Capacity
MMBtu/hr
7,410
Ash Content (A)
13.5
% (provided by the source)
Pollutant
PM10b
PM2.5b
SO2c
NOXd
VOCe
COd
0.06
0.729
(0.054A)
0.324
(0.024A)
0.10
0.24
0.05
0.15
(lbs/MMBtu)
(lbs/ton)
(lbs/ton)
(lbs/MMBtu)
(lbs/MMBtu)
(lbs/ton)
(lbs/MMBtu)
1,947
1,097
488
3,246
7,789
75.3
4,868
PMa
Emission Factor
Potential to Emit in (tons/yr)
a
PM emission factor is the emission limit in 40 CFR 49.5513(d)(2).
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).
b
d
The NOX and CO emission factors are based on the emission limits in the PSD Permit AZ 08-01A, issued on 2/8/12.
e
VOC emission factor is from AP-42, Tables 1.1-19 (09/98).
The heating value of the coal used at this plant is 21.562 MMBtu/ton, provided by the source.
Methodology
PTE of PM10, PM2.5, and VOC (tons/yr) = Max. Heat Input (MMBtu/hr) / 21.562 MMBtu/ton x Emission Factor (lbs/ton) x 8760 hrs/yr x 1 ton/2,000 lbs
PTE of PM, SO2, NOx and CO (tons/yr) = Max. Heat Input (MMBtu/hr) x Emission Factor (lbs/MMBtu) x 8760 hr/yr x 1 ton/2,000 lbs
Page 4 of 16 SOB APP A
Appendix A: Emission Calculations
HAP Emissions
From the Coal Fired Boilers U1 through U3
Company Name:
Address:
Permit No.:
Reviewer:
Date:
Navajo Generating Station
5 miles east of Page, off U.S. Highway 98, Page, AZ 86040
NN-OP-15-06
ERG/YC
September 4, 2015
Emission Unit:
Max. Heat Input Capacity (MMBtu/hr):
Boiler U1
Boiler U2
Boiler U3
7,410
7,410
7,410
PTE of HAP for B2
(tons/yr)
1.00E-06
PTE of HAP for B3
(tons/yr)
1.00E-06
Pollutant
Emission Factor
Unit
Total PCDD
6.66E-10
(lbs/ton)
PTE of HAP for B1
(tons/yr)
1.00E-06
Total PCDF
Total PAH
1.09E-09
2.08E-05
(lbs/ton)
1.64E-06
1.64E-06
1.64E-06
(lbs/ton)
0.03
0.03
0.03
Acetaldehyde
5.70E-04
(lbs/ton)
0.86
0.86
0.86
Acetophenone
1.50E-05
(lbs/ton)
0.02
0.02
0.02
Acrolein
2.90E-04
(lbs/ton)
0.44
0.44
0.44
Benzene
1.30E-03
(lbs/ton)
1.96
1.96
1.96
Benzyl Chloride
7.00E-04
(lbs/ton)
1.05
1.05
1.05
DEHP
7.30E-05
(lbs/ton)
0.11
0.11
0.11
Bromoform
3.90E-05
(lbs/ton)
0.06
0.06
0.06
Carbon Disulfide
1.30E-04
(lbs/ton)
0.20
0.20
0.20
2-Chloroacetophenone
7.00E-06
(lbs/ton)
0.01
0.01
0.01
Chlorobenzene
2.20E-05
(lbs/ton)
0.03
0.03
0.03
Chloroform
5.90E-05
(lbs/ton)
0.09
0.09
0.09
Cumene
5.30E-06
(lbs/ton)
0.01
0.01
0.01
Cyanide
2.50E-03
(lbs/ton)
3.76
3.76
3.76
2,4-Dinitrotoluene
2.80E-07
(lbs/ton)
0.00
0.00
0.00
Dimethyl Sulfate
4.80E-05
(lbs/ton)
0.07
0.07
0.07
Ethyl Benzene
9.40E-05
(lbs/ton)
0.14
0.14
0.14
Ethyl Chloride
4.20E-05
(lbs/ton)
0.06
0.06
0.06
Ethylene Dichloride
4.00E-05
(lbs/ton)
0.06
0.06
0.06
Ethylene Dibromide
1.20E-06
(lbs/ton)
0.00
0.00
0.00
Formaldehyde
2.40E-04
(lbs/ton)
0.36
0.36
0.36
Hexane
6.70E-05
(lbs/ton)
0.10
0.10
0.10
Isophorone
5.80E-04
(lbs/ton)
0.87
0.87
0.87
Methyl Bromide
1.60E-04
(lbs/ton)
0.24
0.24
0.24
Methyl Chloride
5.30E-04
(lbs/ton)
0.80
0.80
0.80
Methyl Hydrazine
1.70E-04
(lbs/ton)
0.26
0.26
0.26
Methyl Methacrylate
2.00E-05
(lbs/ton)
0.03
0.03
0.03
Methyl Tert Butyl Ether
3.50E-05
(lbs/ton)
0.05
0.05
0.05
Methylene Chloride
2.90E-04
(lbs/ton)
0.44
0.44
0.44
Phenol
1.60E-05
(lbs/ton)
0.02
0.02
0.02
Propionaldehyde
3.80E-04
(lbs/ton)
0.57
0.57
0.57
Tetrachloroethylene
4.30E-05
(lbs/ton)
0.06
0.06
0.06
Toluene
2.40E-04
(lbs/ton)
0.36
0.36
0.36
1,1,1-Trichloroethane
2.00E-05
(lbs/ton)
0.03
0.03
0.03
Styrene
2.50E-05
(lbs/ton)
0.04
0.04
0.04
Xylenes
3.70E-05
(lbs/ton)
0.06
0.06
0.06
Vinyl Acetate
7.60E-06
(lbs/ton)
0.01
0.01
0.01
Antimony
1.80E-05
(lbs/ton)
0.03
0.03
0.03
Arsenic
4.10E-04
(lbs/ton)
0.62
0.62
0.62
Beryllium
2.10E-05
(lbs/ton)
0.03
0.03
0.03
Cadmium
5.10E-05
(lbs/ton)
0.08
0.08
0.08
Chromium
2.60E-04
(lbs/ton)
0.39
0.39
0.39
Chromium (VI)
7.90E-05
(lbs/ton)
0.12
0.12
0.12
Cobalt
1.00E-04
(lbs/ton)
0.15
0.15
0.15
Lead
4.20E-04
(lbs/ton)
0.63
0.63
0.63
Manganese
4.90E-04
(lbs/ton)
0.74
0.74
0.74
Mercury*
1.20E-06
0.04
0.04
0.04
Nickel
2.80E-04
(lbs/MMBtu)
(lbs/ton)
0.42
0.42
0.42
Selenium
1.30E-03
(lbs/ton)
1.96
1.96
1.96
Hydrogen Fluoride*
Hydrogen Chloride*
5.30E-05
7.70E-05
(lbs/MMBtu)
(lbs/MMBtu)
1.72
2.50
1.72
2.50
1.72
2.50
22.7
22.7
Total
22.7
Note: Emission factors are from AP-42, Tables 1.1-12, 1.1-13, 1.1-14, and 1.1-18 for Coal Combustion (09/98).
* Hg emission factor is based on the Hg emission limit in 40 CFR 63, Subpart UUUUU.
** HF and HCl emission factors are based on the stack testing results in April, 2010, provided by the source.
The heating value of the coal used at this plant is 21.562 MMBtu/ton, provided by the source.
Methodology
PTE of HAP (tons/yr) = Max. Heat Input (MMBtu/hr) / 21.6 MMBtu/ton x Emission Fator (lbs/ton) x 8760 hrs/yr x 1 ton/2000 lbs
PTE of Hg, HF, and HCl (tons/yr) = Max. Heat Input (MMBtu/hr) x Emission Factor (lbs/MMBtu) x 8760 hr/yr x 1 ton/2,000 lbs
Page 5 of 16 SOB App A
Appendix A: Emission Calculations
No. 2 Fuel Oil Combustion
(MMBtu/hr > 100)
From Two (2) 308 MMBtu/hr Auxiliary Boilers
Company Name:
Address:
Permit No.:
Reviewer:
Date:
Heat Input Capacity
MMBtu/hr
308
Navajo Generating Station
5 miles east of Page, off U.S. Highway 98, Page, AZ 86040
NN-OP-15-06
ERG/YC
September 4, 2015
Max. Fuel Usage
(kgal/hr)
(each)
2.24
S = Weight % Sulfur
(each)
Operation Hour Limit*
(hrs/yr)
0.05
Pollutant
SO2
876
PM
PM10
PM2.5
NOx
VOC
CO
Emission Factor in lbs/kgal
2.00
1.00
0.25
7.1
(142 S)
24.0
0.2
5.0
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
Page 6 of 16 SOB App A
Appendix A: Emission Calculations
HAP Emissions
From Two (2) 308 MMBtu/hr Auxiliary Boilers
Company Name:
Address:
Permit No.:
Reviewer:
Date:
Heat Input Capacity
MMBtu/hr
308
Navajo Generating Station
5 miles east of Page, off U.S. Highway 98, Page, AZ 86040
NN-OP-15-06
ERG/YC
September 4, 2015
Max. Fuel Usage
(kgal/hr)
(each)
Emission Factor in lbs/kgal
Potential to Emit in tons/yr for 2 units
2.24
Operation Hour Limit*
(hrs/yr)
(each)
876
Chloride
3.47E-01
Nickel
8.45E-02
Pollutant
Fluoride
3.73E-02
Vanadium
3.18E-02
Formaldehyde
3.30E-02
Total HAPs
6.05E-01
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
Page 7 of 16 SOB App A
Appendix A: Emission Calculations
PM, PM10, and PM2.5 Emissions
From Coal Handling Operations
Company Name:
Address:
Permit No.:
Reviewer:
Date:
PM2.5
Emission
Factor*
(lbs/ton)
0.00010
Control Method
Control Efficiency
(%)
PTE of PM after
Control (tons/yr)
0.00010
PM10
Emission
Factor*
(lbs/ton)
0.00010
Wet Dust Suppression
50.0%
2.190
2.190
0.00014
4.60E-05
1.30E-05
Wet Dust Suppression
50.0%
0.736
0.242
0.068
0.00014
4.60E-05
1.30E-05
Dust Collector DC-8
99.0%
0.044
0.015
0.004
Number of
Units
Max. Capacity
(tons/hr/unit)
PM Emission
Factor*
(lbs/ton)
Railcar Unloading
1
10,000
Feeders
12
200
Conveyors BC-1 through BC-4
4
1,800
Unit Description
Navajo Generating Station
5 miles east of Page, off U.S. Highway 98, Page, AZ 86040
NN-OP-15-06
ERG/YC
September 4, 2015
PTE of PM10 after PTE of PM2.5 after
Control (tons/yr) Control (tons/yr)
2.190
Conveyor BC-4A
1
100
0.00014
4.60E-05
1.30E-05
Dust Collector DC-8
99.0%
0.001
0.000
0.000
Conveyors BFD-5A and BC-5
2
1,800
0.00014
4.60E-05
1.30E-05
Dust Collector DC-8
99.0%
0.022
0.007
0.002
Conveyor BC-6
1
1,500
0.00014
4.60E-05
1.30E-05
Dust Collector DC-8
99.0%
0.009
0.003
0.001
Conveyors BC-6A through BC-6C
3
1,800
0.00014
4.60E-05
1.30E-05
Wet Dust Suppression
50.0%
1.656
0.544
0.154
Conveyor BC-7
1
1,500
0.00014
4.60E-05
1.30E-05
Wet Dust Suppression
50.0%
0.460
0.151
0.043
Yard Surge Bin YSB-1
1
1,800
0.00014
4.60E-05
1.30E-05
Dust Collector DC-8
99.0%
0.011
0.004
0.001
Conveyors BC-8A and BC-8B
2
1,500
0.00014
4.60E-05
1.30E-05
Dust Collector DC-8
99.0%
0.018
0.006
0.002
Screens BC-8AS and BC-8BS
2
1,500
0.00220
7.40E-04
5.00E-05
Dust Collector DC-8
99.0%
0.289
0.097
0.007
0.002
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
Conveyors BC-9A and BC-9B
2
1,500
0.00014
4.60E-05
1.30E-05
Dust Collector DC-5
99.0%
0.018
0.006
0.002
Conveyors BC-10A and BC-10B
2
1,500
0.00014
4.60E-05
1.30E-05
Dust Collector DC-5
99.0%
0.018
0.006
0.002
Three (3) enclosed cascading
conveying systems
3
1,500
0.00014
4.60E-05
Dust Collectors DC-1 through
DC-4, DC-6, and DC-7
99.0%
1.30E-05
Silos 1A through 1G
7
1.30E-05
Dust Collector/Baghouse
99.0%
3,000
0.00014
4.60E-05
0.028
0.009
0.003
0.129
0.042
0.012
Silos 2A through 2G
7
3,000
0.00014
4.60E-05
1.30E-05
Dust Collector/Baghouse
99.0%
0.129
0.042
0.012
Silos 3A through 3G
7
3,000
0.00014
4.60E-05
1.30E-05
Dust Collector/Baghouse
99.0%
0.129
0.042
0.012
5.91
3.41
2.51
Total
* The emission factors are from AP-42, Table 11.19.2-2 (08/04).
Since the coal received at this facility has high moisture content (6.9%), the controlled emission factors in AP-42, Table 11.19.2-2 are used in the PTE calculations.
Methodology
PTE of PM/PM10/PM2.5 after Control (tons/yr) = Number of Units x Max. Capacity (tons/hr/unit) x Emission Factor (lbs/ton) x 8760 hrs/yr x 1 ton/2000 lbs x (1-Control Efficiency)
Page 8 of 16 SOB App A
Appendix A: Emission Calculations
PM, PM10, and PM2.5 Emissions
From the Coal Storage Piles (Fugitive Emissions)
Company Name:
Address:
Permit No.:
Reviewer:
Date:
Navajo Generating Station
5 miles east of Page, off U.S. Highway 98, Page, AZ 86040
NN-OP-15-06
ERG/YC
September 4, 2015
1. Emission Factors:
According to AP-42, Chapter 13.2.4 - Aggregate Handling and Storage Piles (11/06), the PM/PM10 emission factors for
aggregate handling process can be estimated from the following equation:
1.3
Ef = k x 0.0032 x (U/5)
(M/2)1.4
where:
Ef =
k=
U=
M=
Emission Factor (lbs/ton)
Particle size multiplers =
Mean wind speed (mph) =
Moisture content (%) =
0.74 for PM, 0.35 for PM10, and 0.053 for PM2.5
3.2 mph (provided by the source based on the data in 1999)
3 % (provided by the source)
Therefore,
PM Emission Factor =
PM10 Emission Factor =
PM 2.5 Emission Factor =
0.00075 lbs/ton
0.00036 lbs/ton
0.00005 lbs/ton
2. Potential to Emit PM/PM10/PM2.5 after Control:
Max. Throughput Rate:
Control Efficiency :
3,300 tons/hr
50% for water suppression
PTE of PM after Control (tons/yr) = 3,300 tons/yr x 0.00075 lbs/ton x 8760 hr/yr x 1 ton/2000 lbs x (1-50%) =
5.43 tons/yr
PTE of PM10 after Control (tons/yr) = 3,300 tons/yr x 0.00036 lbs/ton x 8760 hr/yr x 1 ton/2000 lbs x (1-50%) =
2.57 tons/yr
PTE of PM2.5 after Control (tons/yr) = 3,300 tons/yr x 0.00005 lbs/ton x 8760 hr/yr x 1 ton/2000 lbs x (1-50%) =
0.39 tons/yr
Page 9 of 16 SOB App A
Appendix A: Emission Calculations
PM, PM10, and PM2.5 Emissions
From Limestone Handling System
Company Name:
Address:
Permit No.:
Reviewer:
Date:
Navajo Generating Station
5 miles east of Page, off U.S. Highway 98, Page, AZ 86040
NN-OP-15-06
ERG/YC
September 4, 2015
Unit Description
Number of Unit
Truck Unloading
2
38.0
0.0001
0.0001
PM2.5
Emission
Factor*
(lbs/ton)
0.0001
Feeders
2
36.0
0.0030
0.0011
0.0011
Cleanout Conveyors
2
5.00
0.0030
0.0011
Ball Mills
2
36.0
0.0054
0.0024
Max. Capacity
PM Emission
PM10 Emission
(tons/hr)
Factor* (lbs/ton) Factor* (lbs/ton)
Control
Efficiency (%)
PTE of PM
(tons/yr)
PTE of PM
(tons/yr)
PTE of PM2.5
(tons/yr)
0.00
0.03
0.03
0.03
0.00
0.95
0.35
0.35
0.0011
0.00
0.13
0.05
0.05
0.0024
0.00
1.70
0.76
0.76
2.81
1.19
1.19
Total
* The emission factora are from AP-42, Table 11.19.2-2 (08/04). Assume PM2.5 emission factors are equal to PM10 emission factors.
Methodology
PTE of PM/PM10/PM2.5 after control (tons/yr) = Num. of Units x Max. Capacity (tons/hr) x Emission Factor (lbs/ton) x 8760 hr/yr x 1 ton/2000 lbs x (1 - control efficiency)
DC-9
0.001
17,950
99%
Uncontrolled
PM/PM10/PM2.5
Emissions
(tons/yr)
67.4
DC-10
0.001
17,950
0.15
0.67
99%
67.4
DC-11
0.001
12,000
0.10
0.45
99%
45.1
Dust Collector ID
Grain Loading
(gr/acfm)
Flow Rate
(acfm)
Controlled
Controlled
PM/PM10/PM2.5 PM/PM10/PM2.5
Emissions
Emissions
(lbs/hr)
(tons/yr)
0.15
0.67
Total
1.80
Control
Efficiency (%)
180
Methodology
Controlled Emissions (lbs/hr) = Grain Loading (gr/acfm) x Flow Rate (acfm) x 60 mins/hr x 1 lb/7000 gr
Controlled Emissions (tons/yr) = Controlled Emissions (lbs/hr) x 8760 hrs/yr x 1 ton/2000 lbs
Uncontrolled Emissions (tons/yr) = Controlled Emissions (tons/yr) / (1 - Control Efficiency)
PTE of PM after Control =
PTE of PM10 after Control =
PTE of PM2.5 after Control =
2.81 tons/yr + 1.80 tons/yr =
1.19 tons/yr + 1.80 tons/yr =
1.19 tons/yr + 1.80 tons/yr =
4.61 tons/yr
2.98 tons/yr
2.98 tons/yr
Page 10 of 16 SOB App A
Appendix A: Emission Calculations
PM, PM10, and PM2.5 Emissions
From the Limestone Storage Piles (Fugitive Emissions)
Company Name:
Address:
Permit No.:
Reviewer:
Date:
Navajo Generating Station
5 miles east of Page, off U.S. Highway 98, Page, AZ 86040
NN-OP-15-06
ERG/YC
September 4, 2015
1. Emission Factors:
According to AP-42, Chapter 13.2.4 - Aggregate Handling and Storage Piles (11/06), the PM/PM10 emission factors for
aggregate handling process can be estimated from the following equation:
1.3
Ef = k x 0.0032 x (U/5)
(M/2)1.4
where:
Ef =
k=
U=
M=
Emission Factor (lbs/ton)
Particle size multiplers =
Mean wind speed (mph) =
Moisture content (%) =
0.74 for PM, 0.35 for PM10, and 0.053 for PM2.5
3.2 mph (provided by the source based on the data in 1999)
1 % (provided by the source)
Therefore,
PM Emission Factor =
PM10 Emission Factor =
PM2.5 Emission Factor =
0.0035 lbs/ton
0.0017 lbs/ton
0.0003 lbs/ton
2. Potential to Emit PM/PM10/PM2.5 after Control:
Max. Throughput Rate:
Control Efficiency :
600 tons/yr
50% for water suppression
PTE of PM after Control (tons/yr) = 600 tons/yr x 0.0035 x 8760 hr/yr x 1 ton/2000 lbs x (1-50%) =
4.60 tons/yr
PTE of PM10 after Control (tons/yr) = 600 tons/yr x 0.0035 x 8760 hr/yr x 1 ton/2000 lbs x (1-50%) =
2.17 tons/yr
PTE of PM2.5 after Control (tons/yr) = 600 tons/yr x 0.0003 x 8760 hr/yr x 1 ton/2000 lbs x (1-50%) =
0.33 tons/yr
Page 11 of 16 SOB App A
Appendix A: Emission Calculations
PM, PM10, PM2.5, and HAP Emissions
From the Fly Ash Handling System
Company Name:
Address:
Permit No.:
Reviewer:
Date:
Navajo Generating Station
5 miles east of Page, off U.S. Highway 98, Page, AZ 86040
NN-OP-15-06
ERG/YC
September 4, 2015
Number of Units
Max. Capacity
(tons/hr/unit)
PM Emission
Factor*
(lbs/ton)
PM10 Emission
Factor* (lbs/ton)
Fly Ash Silos
2
46
2.20
2.20
PM2.5
Emission
Factor*
(lbs/ton)
2.20
Truck Loading for Fly Ash
2
38
0.61
0.61
0.61
Unit Description
Control Method
Control
Efficiency (%)
PTE of PM after
Control (tons/yr)
Dust Collectors
99.0%
8.87
8.87
Dust Collectors
90.0%
20.3
20.3
20.3
29.2
29.2
29.2
Total
* The emission factors are from AP-42, Table 11.17-4 for Lime Manufacturing Process (02/98).
Assume the PM10 and PM2.5 emissions are equal to PM emissions.
Methodology
PTE of PM/PM10/PM2.5 after Control (tons/yr) = Num of Units x Max. Capacity (tons/hr/unit) x Emission Factor (lbs/ton) x 8760 hr/yr x 1 ton/2000 lbs x (1-Control Efficiency)
Potential to Emit HAPs
HAP
HAP
Concentration*
(ton per ton ash)
PTE of HAP
(tons/yr)
Beryllium
6.097E-06
1.78E-04
Chromium
2.485E-05
7.25E-04
Lead
2.650E-05
7.73E-04
Manganese
1.372E-04
4.00E-03
Nickel
2.893E-05
8.44E-04
Total HAPs
6.52E-03
*HAP concentration values are based on the 4/26/99 NGS coal analysis data.
Methodology
PTE of HAP after Control (tons/yr) = PTE of PM after Control (tons/yr) x HAP Concentration (ton/ton of ash)
PTE of PM10 after PTE of PM2.5 after
Control (tons/yr) Control (tons/yr)
8.87
Page 12 of 16 SOB App A
Appendix A: Emission Calculations
PM, PM10, and PM2.5 Emissions
From the Soda Ash/Lime Handling Systems
Company Name:
Address:
Permit No.:
Reviewer:
Date:
Unit Description
Number of
Units
Max. Capacity
(tons/hr/unit)
Navajo Generating Station
5 miles east of Page, off U.S. Highway 98, Page, AZ 86040
NN-OP-15-06
ERG/YC
September 4, 2015
PM/PM10/PM2.5
Emission Factor*
(lbs/ton)
Soda Ash Silos
4
0.40
2.20
Lime Silos
2
0.57
2.20
Total
PTE of
PM/PM10/PM2.5
Control Method
before Control
(tons/yr)
15.4
Dust Collector
11.0
26.4
Baghouse
Control
Efficiency (%)
99.0%
99.0%
PTE of
PM/PM10/PM2.5
after Control
(tons/yr)
0.15
0.11
0.26
* The emission factors are from AP-42, Table 11.17-4 for Lime Manufacturing Process (02/98).
Assume the PM10 and PM2.5 emissions are equal to PM emissions.
Methodology
PTE of PM/PM10/PM2.5 before Control (tons/yr) = Number of Units x Max. Capacity (tons/hr/unit) x Uncontrolled Emission Factor (lbs/ton) x 8760 hrs/yr x 1 ton/2000 lbs
PTE of PM/PM10/PM2.5 after Control (tons/yr) = PTE of PM/PM10 before Control (tons/yr) x (1-Control Efficiency)
Page 13 of 16 SOB App A
Appendix A: Emission Calculations
PM, PM10, and PM2.5 Emissions
From the Cooling Towers
Company Name:
Address:
Permit No.:
Reviewer:
Date:
Navajo Generating Station
5 miles east of Page, off U.S. Highway 98, Page, AZ 86040
NN-OP-15-06
ERG/YC
September 4, 2015
1. Process Description:
Circulation Flow Rate:
Total Drift:
Total Dissolved Solids:
Density:
% Not Deposited on Site:
813,000
0.0009%
12,000
8.328
10%
gal/min (6 cooling towers total)
of the circulating flow (provided by the source)
ppm
lbs/gal
(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% =
PTE of PM/PM10/PM2.5 (tons/yr) = 4.40 lbs/hr x 8760 hrs/yr x 1 ton/2000 lbs =
4.39 lbs/hr
19.2 tons/yr
Page 14 of 16 SOB App A
Appendix A: Emission Calculations
Fugitive Emissions
From Unpaved Roads
Company Name:
Address:
Permit No.:
Reviewer:
Date:
Navajo Generating Station
5 miles east of Page, off U.S. Highway 98, Page, AZ 86040
NN-OP-15-06
ERG/YC
September 4, 2015
1. Emission Factors:
According to AP42, Chapter 13.2.2 - Unpaved Roads (11/06), the PM/PM10/PM2.5 emission factors for unpaved roads
can be estimated from the following equation:
a
b
E = k x (s/12) x (w/3) x (365-p)/365
where:
E=
s=
w=
k=
a=
b=
p=
emission factor (lb/vehicle mile traveled)
surface material silt content (%) =
mean vehicle weight (tons) =
empirical constant =
empirical constant =
empirical constant =
number of days per year with 0.01 inches precipitation
5.1 % (AP-42, Table 13.2.2-1)
78.1 tons (see the calculations below)
4.9 for PM, 1.5 for PM10, and 0.15 for PM2.5
0.7 for PM, 0.9 for PM10, and 0.9 for PM2.5
0.45
60 (see Fig 13.2.2-1 in AP42)
4.9 x (5.1/12)0.7 x (78.1/3)0.45 x (365-60)/365
0.45
1.5 x (5.1/12)0.9 x (78.1/3) x (365-60)/365
0.9
0.15 x (5.1/12) x (78.1/3)0.45 x (365-60)/365
PM Emission Factor =
PM10 Emission Factor =
PM2.5 Emission Factor =
=
=
=
9.8 lbs/mile
2.52 lbs/mile
0.25 lbs/mile
2. Potential to Emit (PTE) of PM/PM10/PM2.5 Before Control from Unpaved Roads:
Number of
Units
Vehicle Type
Service/Fuel Truck
Service/Fuel Truck
Ash Trucks
Ash Truck
D65 Dozer
D31 Dozer
Rubber Tire Dozer
13 -Yard Loader
6-Yard Loader
2.5-Yard Loaders
7-Yard Loader
8,000-Gallon Waterpulls
12,000-Gallon Waterpulls
12-Yard Crystallizer Trucks
12-Yard Dump Trucks
14G Grader
EI 300 Excavator
140H Grader
Road Trucks
724 Vac Truck
2.5 Yar Loader (928)
NPG-797 Bucket Truck
NPG-733 Bucket Truck
Total
1
1
3
1
1
1
1
1
1
2
1
1
1
3
4
1
1
1
2
1
3
1
1
Total Vehicle
Ave. Vehicle
Vehicle Miles Miles Traveled
Weight*
Traveled* (VMT)
(VMT)
(tons)
(miles/day/unit)
(miles/yr)
16.5
13.2
102
102
22.0
8.00
33.5
72.0
24.0
12.5
54.5
36.5
115
13.0
11.6
28.0
34.0
19.8
11.0
19.8
12.5
20.6
14.6
15.0
18.0
90.0
12.0
5.00
2.00
1.00
7.00
2.00
2.00
3.00
30.0
127
2.00
1.00
10.0
0.14
1.00
1.00
3.00
2.00
40.0
46.0
5,475
6,570
98,550
4,380
1,825
730
365
2,555
730
1,460
1,095
10,950
46,355
2,190
1,460
3,650
51
365
730
1,095
2,190
14,600
16,790
224,161
Traffic
Component
(%)
Component
Vehicle
Weight
(tons)
PTE of PM
(tons/yr)
2.44%
2.93%
44.0%
1.95%
0.81%
0.33%
0.16%
1.14%
0.33%
0.65%
0.49%
4.88%
20.7%
0.98%
0.65%
1.63%
0.02%
0.16%
0.33%
0.49%
0.98%
6.51%
7.49%
100%
0.40
0.39
44.8
1.99
0.18
0.03
0.05
0.82
0.08
0.08
0.27
1.78
23.8
0.13
0.08
0.46
0.01
0.03
0.04
0.10
0.12
1.34
1.09
78.1
26.7
32.0
480
21.4
8.9
3.56
1.78
12.5
3.56
7.12
5.34
53.4
226
10.7
7.12
17.8
0.25
1.78
3.56
5.34
10.7
71.2
81.9
1,093
* This information is provided by the source.
Methodology
Component Vehicle Weight = Ave. Vehicle Weight (tons) x Traffic Component (%)
(Note that the summation of the component vehicle weight equals the Mean Vehicle Weight.)
VMT(miles/yr) = VMT (miles/day/unit) x 365 days/yr x Number of Units
PTE of PM/PM10/PM2.5 (tons/yr) = VMT (miles/yr) x Emission Factor (lbs/mile) x 1 ton/ 2000 lbs
3. Potential to Emit (PTE) of PM/PM10/PM2.5 after Control from Unpaved Roads:
Control Efficiency :
50% for continuous water suppression
PTE of PM after Control =
PTE of PM10 after Control =
PTE of PM2.5 after Control =
1,093 tons/yr x (1-50%) =
282 tons/yr x (1-50%) =
28.2 tons/yr x (1-50%) =
546 tons/yr
141 tons/yr
14.1 tons/yr
PTE of PM10 PTE of PM2.5
(tons/yr)
(tons/yr)
6.89
8.3
124
5.51
2.30
0.92
0.46
3.21
0.92
1.84
1.38
13.8
58.3
2.75
1.84
4.59
0.06
0.46
0.92
1.38
2.75
18.36
21.12
282
0.69
0.83
12.4
0.55
0.23
0.09
0.05
0.32
0.09
0.18
0.14
1.38
5.83
0.28
0.18
0.46
0.01
0.05
0.09
0.14
0.28
1.84
2.11
28.2
Page 15 of 16 SOB App A
Appendix A: Emission Calculations
Internal Combustion Engines
From the Diesel Emergency Generators
Company Name:
Address:
Permit No.:
Reviewer:
Date:
Power Output
Horse Power (HP)
2,861
Navajo Generating Station
5 miles east of Page, off U.S. Highway 98, Page, AZ 86040
NN-OP-15-06
ERG/YC
September 4, 2015
Operation Limit*
(hrs/yr)
(9 units total)
Emission Factor in lb/HP-hr
Potential to Emit (PTE) in tons/yr
500
PM
Pollutant
PM10/PM2.5
SO2
NOx
VOC
CO
2.20E-03
2.20E-03
2.05E-03
3.10E-02
2.47E-03
6.68E-03
1.57
1.57
1.47
22.2
1.77
4.78
Emission factors are from AP-42, Table 3.3-1 (10/96).
Assume PM10/PM2.5 emissions equal PM emissions. TOC (total organic compounds) emissions equal VOC emissions.
Note:
As defined in the September 6, 1995 memorandum from John S. Seitz of US EPA on the subject of "Calculating Potential to Emit for
Emergency Generators", an emergency generator's sole function is to provide back-up power when power from the local utility is interrupted.
The only circumstances under which an emergency generator would operate when utility power is available are during operator training or
brief maintenance checks. The generator's potential to emit is based on an operating time of 500 hours per year as set forth in the EPA memo.
Methodology
PTE (tons/yr) = Power Output (HP) x Emission Factor (lb/HP-hr) x Operation Limit (hr/yr) x 1 ton/2000 lbs
Page 16 of 16 SOB App A
Appendix A: Emission Calculations
PTE Summary
Company Name:
Address:
Permit No.:
Reviewer:
Date:
Navajo Generating Station
5 miles east of Page, off U.S. Highway 98, Page, AZ 86040
NN-OP-15-06
ERG/YC
September 4, 2015
Limited Potential To Emit after Control
PM
PM10
PM2.5
SO2
NOx
VOC
CO
Total HAPs
Boiler U1
Boiler U2
Boiler U3
Auxiliary Boilers
Coal Handling Operations
Coal Piles (Fugitive)
Limestone Handling Operations
Limestone Piles (Fugitive)
Fly Ash Handling Operations
Soda Ash/Lime Handling Operations
Cooling Towers
PAC Storage Silos*
Unpaved Roads associated with PAC and
CaBr2 delivery (Fugitive)*
Unpaved Roads (Fugitive)
Emergency Generators (Insignificant)
Other Insignificant Activities**
1,947
1,947
1,947
3.92
5.91
5.43
4.61
4.60
29.2
0.26
19.2
0.90
1.28
1,097
1,097
1,097
1.96
3.41
2.57
2.98
2.17
29.2
0.26
19.2
0.90
0.33
488
488
488
0.49
2.51
0.39
2.98
0.33
29.2
0.26
19.2
0.90
0.03
3,246
3,246
3,246
13.9
-
7,789
7,789
7,789
47.1
-
75.3
75.3
75.3
0.39
-
4,868
4,868
4,868
9.81
-
22.7
22.7
22.7
1.19
0.01
-
546
1.57
15.3
141
1.57
15.3
14.1
1.57
15.3
1.47
-
22.2
-
1.77
5.00
4.78
-
Negligible
Negligible
Total PTE (tons/yr)
6,481
3,513
1,550
9,752
23,437
233
14,620
69.3
Emission Units
Note: (*) The PTE information for these units is from Tribal NSR Permit #T-0004-NN, issued on 08/26/15.
(**) PM10 emissions are from the welding and the abrasive blasting operations and are based on the information provided in the permit application received on
01/04/13. Assume PM10 emissions are equal to PM/PM2.5 emissions. VOC/HAP emissions are the estimated emissions from the parts cleaning, surface
coating operations, and the storage tanks.
Dust Control Plan
For
Navajo Generating Station
Pursuant to the
Source-Specific
Federal Implementation Plan
40 CFR Part 49
Prepared By:
SALT RIVER PROJECT
Navajo Generating Station
P.O. Box 850
Page, AZ 86040
February 2015
Table of Contents
1. INTRODUCTION AND PURPOSE
2. FACILITY DETAILS
3. GEOGRAPHY AND CLIMATE
4. DUST SUPPRESSION METHODS
Federal Implementation Plan Requirements - 40 CFR Part 49 §49.24(d)(3)
4.1
ROADWAYS
4.2
MATERIAL STORAGE
4.3
COAL HANDLING
4.4
FLY ASH HANDLING
4.5
LIMESTONE HANDLING
Navajo Nation EPA Title V Permit # NN-ROP-05-06, Section II.D. NSPS Subpart OOO
5. INSPECTIONS
6. RECORDKEEPING AND REPORTING
7. ROADWAY EQUIPMENT
8. TRAINING
9. ATTACHMENTS
9.1
Facility Map
9.2
Weekly Inspection Forms
9.3
Visible Emissions Form
1.0 INTRODUCTION AND PURPOSE
Salt River Project’s (SRP’s) Navajo Generating Station (NGS) facility is committed to
responsible and sustainable stewardship of the environment; and compliance with the
requirements of the United States Environmental Protection Agency’s (EPA’s) Federal
Implementation Plan (FIP) for NGS, recorded in the Federal Register under 40 CFR Part 49. This
Dust Control Plan (DCP) describes methods and procedures to minimize emissions from point
and non-point dust sources and maintain compliance with the FIP.
FIP conditions in 40 CFR Part 49 §49.24(d)(3) specify that:
“Each owner or operator shall operate and maintain the existing dust suppression
methods for controlling dust from the coal handling and storage facilities. Within 90
days after promulgation of these regulations the owner or operator shall submit to the
Regional Administrator a description of the dust suppression methods for controlling
dust from the coal handling and storage facilities, fly ash handling and storage, and
road sweeping activities. Each owner or operator shall not emit dust with opacity
greater than 20% from any crusher, grinding mill, screening operation, belt conveyor,
truck loading or unloading operation, or railcar unloading station.”
2.0 FACILITY DETAILS
NGS is a participant owned generating plant managed by SRP. NGS is located on leased land 5
miles southeast of Page Arizona at 4365 feet (elevation). The participants are U.S. Bureau of
Reclamation (24.3% ownership), Los Angeles Department of Water and Power (21.2%), Salt
River Project (21.7%), Arizona Public Service (14.0%), Nevada Power (11.3%) and Tucson
Electric Power Co. (7.5%). NGS is a three-unit coal fired power plant (supercritical design
tangentially-fired boilers) generating 2250 net megawatts of power.
Bituminous coal is mined by Peabody Energy at the Black Mesa Mine Complex and delivered by
electric rail to NGS. Coal is then transferred via enclosed conveyor systems for burning in the
boilers or stacked out to a storage pile for later use.
The management of coal combustion residues and the delivery of limestone for the SO2 scrubbers
is contracted to a third party entity but SRP remains the responsible party for truck loading and
unloading operations, material transfer, storage, and disposal activities. Coal combustion residues
include flyash, bottom ash, and scrubber byproducts. Bottom ash and scrubber byproducts are
handled in a wet state which minimizes the potential for dust emissions and these materials are
not addressed in the FIP and in this document.
3.0 GEOGRAPHY AND CLIMATE
NGS is located in an arid desert environment receiving an annual average of seven and half
inches of precipitation. The surrounding geologic formations include outcroppings of the Carmel
formation, Page Sandstone, and Navajo Sandstone. Weathering of these formations have created
substrates of unconsolidated aeolian sands and partially stabilized dune deposits with sparse
vegetation.
4.0 DUST SUPPRESSION METHODS
The FIP requires in 40 CFR Part 49 §49.24(d)(3) a description of the dust suppression methods
for coal handling and storage facilities, fly ash handling and storage, and road sweeping activities.
The tables contained in this section outline preventive and mitigating control measures as
guidelines to minimize dust emissions from paved and unpaved roads, storage piles, and the
material handling related to coal, fly ash, and limestone.
4.1 Roadways
Dust emissions from roadways are mitigated using control measures outlined below. Main
trafficked areas are sprayed with water daily (weather permitted) and speed limits are observed.
During winter months, ice formation may preclude water spraying due to safety consideration.
Roadway Non-Point Sources: One or more of the following control measures will be
implemented to minimize dust emissions from roadway sources.
TABLE 1.0 Control Measure Guidelines:
Source:
Roadway Dust Control Measures
1. Water spray roads
Paved Roads:
2. Speed reduction
Traffic Activity
3. Limit Traffic
4. Sweeping of roads
1. Water spray roads
Unpaved Roads:
2. Speed reduction
Traffic Activity
3. Limit traffic
4. Gravel surface
5. Chemical stabilization
1. Clean vehicles before entering roadway
Carryout
2. Pave access road near plant site exit
3. Rapid cleanup after spill events
Monitor: Verify control measures weekly.
4.2 Material Storage
Table 2.0 Control Measure Guidelines:
Material Storage
Control techniques applicable to outdoor material storage piles fall into distinct categories
as related to handling operations (including traffic around piles) and mitigating wind
erosion. In both cases, the control can be achieved by implementing one or more of the
following strategies: (a) source extent reduction, (b) source improvement related to work
practices and transfer equipment (load-in and load-out operations), and (c) surface
treatments.
Material Disturbance and Wind Erosion Control Measures:
Source control
1. Minimize exposed surface area
2. Minimize surface disturbances and material handling
Source improvement
1. Reduce drop height when handling material
2. Maintain moisture and crust, as applicable
3. Shelter from wind, as applicable
Surface treatment
1. Water Spraying, as applicable
2. Chemical stabilization
Monitor: Verify control measures weekly.
4.3 Coal Handling
SRP’s responsibilities extend to all aspects of coal handling and storage; this includes
implementing dust control measures for the following:
Coal Handling Non-Point Sources: One or more of the following control measures will be
implemented by NGS to minimize dust emissions from the potential sources listed below:
TABLE 3.0 Control Measure Guidelines:
Source: (Unit ID)
Material Handling Control Measures
1. Shelter from wind - enclosure
Material Handling: (CT1)
Railroad car unloading
2. Reduce drop height – minimum hopper level
operations
maintained
3. Watering spraying
(L1-L12) Twelve hopper
1. Shelter from wind - enclosure
feeders
2. Water spraying
3. Chemical stabilization
(BC-1) Belt Conveyor
1. Shelter from wind - enclosure
2. Water spraying
3. Chemical stabilization
1. Shelter from wind - enclosure
(BC-2)
2. Maintain moisture
1. Shelter from wind - enclosure
(BC-3)
2. Maintain moisture
1. Shelter from wind - enclosure
(BC-4)
2. Maintain moisture
1. Shelter from wind - enclosure
(BC-4A)
2. Maintain moisture
1. Shelter from wind - enclosure
(BFD-5A)
Belt Feeder Deck
(BC-5)
(BC-6A) 1 of 3 stacker /
reclaimer reversible
conveyers
(BC-6B) 2 of 3 stacker
conveyer only
(BC-6C) 3 of 3 stacker /
reclaimer reversible
conveyers
(BC-6)
(BC-7) One conveyor to the
emergency reclaim hopper
Wind Erosion: (CS) Outdoor
coal storage piles
2.
1.
2.
1.
2.
3.
1.
2.
1.
Maintain moisture
Shelter from wind - enclosure
Maintain moisture
Shelter from wind - enclosure
Water spraying
Chemical stabilization
Shelter from wind - enclosure
Maintain moisture
Shelter from wind - enclosure
1.
2.
3.
1.
2.
3.
1.
2.
3.
Shelter from wind - enclosure
Water spraying
Chemical stabilization
Shelter from wind - enclosure
Water spraying
Chemical stabilization
Maintain moisture
Water spraying
Chemical stabilization
Monitor: Verify control measures weekly.
Coal Handling Point Sources: The potential sources listed in Table 4.0 utilize particulate control
devices to control emissions.
TABLE 4.0 Emission Control Devices:
Unit ID / Stack ID:
Control Device
YSB-1
BC-8A & BC-8B
BC-8A & BC-8B
screening operation
PSB-1
BC-9A & BC-9B
BC-10A & BC-10B
CC-1A thru CC-9A;
CC-1B thru CC-9B;
BC-11A & BC-11B
Silos 1A thru 1G
Make / Size
DC-8 (Sample Bldg
– 100 feet
elevation)
Peabody Lugar LT
(Air Flow
20,000 acfm)
DE-5
(Cascade Enclosure
- 135 feet
elevation)
SIEMENS Dust
Eliminator System
Stack Details
Exit opening facing
eastward on east
side of EF-8.
Opening: 1.5 feet by
2 feet
Exit opening is
outside building
facing west.
Opening: 3 feet by 3
feet
SEE BELOW – The dust emissions from the cascading conveyors
are also controlled by DE-1 through DE-4 and DE-6 & DE-7.
DE-1 & DE-2
(Cascade Enclosure
- 135 feet
elevation)
SIEMENS and
PR-1, SR-1 & EX-1
Exit opening is
outside building
facing east.
Opening: 3 feet by
3 feet
Silos 2A thru 2G
Silos 3A thru 3G
DE-3 & DE-4
(Cascade Enclosure
- 135 feet
elevation)
SIEMENS and
PR-2, SR-2 & EX-2
DE-6 & DE-7
(Cascade Enclosure
- 135 feet
elevation)
SIEMENS and
PR-3, SR-3 & EX-3
Exit opening is
outside building
facing east.
Opening: 3 feet by
3 feet
Exit opening is
outside building
facing east.
Opening: 3 feet by
3 feet
Monitor: Weekly visible emission observations will be recorded for each control device listed
above that is operating. If visible emissions are observed, opacity readings will be conducted in
accordance with EPA Method 9.
4.4 Fly Ash Handling
SRP’s responsibilities extend to all aspects of flyash handling and storage although some
activities are managed by a third party contractor:
Fly Ash Non-point Sources: The activities in Table 5.0 are managed by a third party contractor
and activities in Table 5.1 are managed by SRP. One or more of the following control measures
are implemented to minimize dust emissions from these potential sources.
TABLE 5.0 Control Measure Guidelines:
Source:
Material Handling and Roadway Control Measure(s)
1. Drop height reduction
Material Handling:
2. Moisture retention, apply as needed
Silo 1 Loading
(open bed haul truck
3. Wind sheltering, loading chute
loading operations)
1. Drop height reduction
Silo 2 Loading
(open bed haul truck
2. Moisture retention, apply as needed
loading operations)
3. Wind sheltering, loading chute
1. Limit Traffic
Paved Roads:
2. Sweeping of roads
Traffic Activity
3. Water Flushing of roads
1. Clean vehicles before entering roadway
Carryout
2. Pave access road near site exit
3. Rapid cleanup after event
1. Reducing overloaded trucks
Spillage
2. Wetting materials being hauled
1. Water Suppression
Unpaved Roads:
2. Chemical stabilization
Traffic Activity
3. Speed reduction
4. Limit traffic
5. Gravel surface
TABLE 5.1 Control Measure Guidelines:
Material Handling/Processing Control Measure(s)
Source:
Spillage (conveyance from
1. Enclosure
post-furnace to enclosed silos)
2. Rapid cleanup after spill events
Monitor: Verify control measures weekly.
Flyash Point Sources: The potential sources listed in Table 6.0 are managed by SRP and utilize
particulate control devices to control emissions.
TABLE 6.0 Emission Control Devices:
Unit ID / Stack ID:
Control Device
DC-S1/2
Silo 1
(storage activity)
(baghouse on top of
Silo 1)
Make / Size
Scientific Dust
Collectors
Silo 2
(storage activity)
DC-S3
(baghouse on top of
Silo 2)
Scientific Dust
Collectors
Silo 1 Loading
(enclosed fly ash
trucks loading)
DC-S1/2
(baghouse on top of
Silo 1)
Scientific Dust
Collectors
Silo 2 Loading
(enclosed fly ash
trucks loading)
DC-S3
(baghouse on top
Silo 2)
Scientific Dust
Collectors
Stack Details
EX Fan facing
south on west end
of baghouse.
Opening: 2.5 feet
by 4 feet
EX Fan facing
south on west end
of baghouse.
Opening: 2.5 feet
by 4 feet
Facing skyward on
east side of
baghouse.
Opening: 1 foot by
2 feet
EX Fan facing
south on west end
of baghouse.
Opening: 2.5 feet
by 4 feet
Monitor: Weekly visible emission observations will be recorded for each control device listed
above that is operating. If visible emissions are observed, opacity readings will be conducted in
accordance with EPA Method 9.
4.5 Limestone Handling
All Limestone Non-Point and Point sources are managed in accordance with the NGS Title V
Operating Permit, Section II.D. NSPS, Subpart OOO requirements.
Limestone Handling Non-point Sources:
Table 7.0 Control Measure Guidelines:
Source:
Control Measure(s)
Not Applicable - Truck dumping of non-metallic minerals into
Material Handling:
any screening operation, feed hopper, or crusher is exempt
Unloading Bay A and B
(truck unloading operations)
per 40 CFR 60.672(d)
LS – Limestone Storage Pile
1. Water suppression
2. Maintain visible surface crust
Monitor: Weekly observations will be recorded.
Limestone Handling Point Sources: The potential sources listed in Table 8.0 utilize particulate
control devices to control emissions.
Table 8.0 Control Devices:
Unit ID / Stack ID:
Control Device
O-LSH-HOP-A
O-LSH-FDR-A
O-LSH-CNV-A
DC-9
(Baghouse on SW
corner of
Limestone
Handling)
O-LSH-HOP-B
O-LSH-FDR-B
O-LSH-CNV-B
DC-10
(Baghouse on NE
corner of
Limestone
Handling)
O-LSH-SILO-A&B
DC-11
(Baghouse on W
side of Limestone
Prep Building)
Make / Size
Mac Equipment
Company, Serial
number 95FMCF361Filter,
12X12X38.1 feet
tall, 22,000 pounds
and a design
capacity of 18,000
ACFM.
Mac Equipment
Company, Serial
number 96MCF361Filter,
12X12X38.1 feet
tall, 22,000 pounds
and a design
capacity of 18,000
ACFM.
Mac Equipment
Company, Serial
number 95-FMCF07-007, Model
number 96MCF255Filter,
10X10X32.2 feet
tall, 9,200 pounds
and a design
capacity of 12,681
ACFM.
Stack Details
Facing skyward.
Opening: 34 inch
diameter pipe
Facing skyward.
Opening: 34 inch
diameter pipe
Facing skyward.
Opening: 30 inch
diameter pipe
Monitor: Weekly observations will be recorded.
Opacity limitations are as follows:
 No greater than 15% from any crusher without a capture system.
 No greater than 10% from any transfer point without a capture system.
 No greater than 7% from any stack emissions or building vent enclosing any transfer
point or crushing operations.
 Truck dumping of nonmetallic minerals into any screening operations, feed hopper or
crusher is exempt per 40 CFR 60.672(d).
4.5 Soda Ash and Lime Handling
All Soda Ash Point sources are managed in accordance with the FIP conditions in 40 CFR Part 49
§49.24(d)(3).
Soda Ash and Lime Handling Point Sources: The potential sources listed in Table 9.0 utilize
particulate control devices to control emissions.
Table 9.0
Control Devices:Unit
ID / Stack ID:
SAB-1A, SAB-2A,
SAB-1B, SAB-2B
(water treatment
soda ash storage
activity)
LB-1 & LB-2
(water treatment
lime storage activity)
Control Device
Make / Size
Stack Details
DC-BH6
(baghouse on top of
Bin 3)
Scientific Dust
Collectors
Exhaust opening
facing south on top
of baghouse.
Opening: 6” I.D.
DC-BH7
(baghouse on top of
Bin 1)
Scientific Dust
Collectors
Exhaust opening
facing south on top
of baghouse.
Opening: 6” I.D.
Monitor: Weekly observations will be recorded.
Opacity limitations are as follows:
 No greater than 20% from any capture system.
5.0 INSPECTIONS
The effectiveness of control measures will be evaluated using regular inspections and
documentation of visible emissions, as applicable. Dust control devices will be operated and
maintained with opacity emission limits specified in the Federal Implementation Plan - 40 CFR
Part 49 §49.24(e)(8).
Inspections shall be performed weekly by trained and certified Method 9 observers. For nonpoint sources the inspectors shall document active control measures that are being used to
minimize dust emissions. In the case of point sources, the observers shall perform visible
emission observations. If visible emissions are observed, opacity readings will be conducted in
accordance with EPA Method 9.
See Section 9 – Weekly Inspection Forms
6.0 RECORD KEEPING AND REPORTING
SRP will maintain records of weekly inspection records, Method 9 certification training, and
Method 9 observations.
SRP will make reports as necessary in accordance with the Federal Implementation Plan - 40
CFR Part 49 §49.24(f).
For excess emissions, SRP will notify the Navajo Environmental Protection Agency Director and
the U.S. Environmental Protection Agency Regional Administrator by telephone or in writing
within one business day.
The notifications will be sent to the Director, Navajo Environmental Protection Agency, by mail
to: P.O. Box 339, Window Rock, Arizona 86515, or by facsimile to: (928) 871–7996 (facsimile),
and to the Regional Administrator, U.S. Environmental Protection Agency Region 9, by mail to
the attention of Mail Code: AIR–5, at 75 Hawthorne Street, San Francisco, California 94105, by
facsimile to: (415) 947–3579 (facsimile), or by e-mail to:[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
SRP RENTAL
Make: Komatsu, Model Mega, 13,000 gallon capacity
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)
Signature:
Walter Begay
Jon Adams
LD Shakespear
Date:
SRP/NGS
Non-Point Sources (Coal Handling and Storage)
MATERIAL HANDLING AND STORAGE CONTROL MEASURES
Source (Unit ID)
Control Measure(s) Implemented (Circle)
Comments:
1. Shelter from wind - enclosure
Material
2. Reduce drop height – minimum hopper level
Handling: (CT1)
Railroad car
maintained
unloading
3. Water spraying
operations
(L1-L12) Twelve
1. Shelter from wind - enclosure
hopper feeders
2. Watering
3. Chemical stabilization
(BC-1) Belt
1. Shelter from wind - enclosure
Conveyor
2. Water spraying
3. Chemical stabilization
1. Shelter from wind - enclosure
(BC-2)
2. Maintain moisture
1. Shelter from wind - enclosure
(BC-3)
2. Maintain moisture
1. Shelter from wind - enclosure
(BC-4)
2. Maintain moisture
1. Shelter from wind - enclosure
(BC-4A)
2. Maintain moisture
1. Shelter from wind - enclosure
(BFD-5A)
2. Maintain moisture
Belt Feeder Deck
1. Shelter from wind - enclosure
(BC-5)
2. Maintain moisture
(BC-6A) 1 of 3
1. Shelter from wind - enclosure
stacker / reclaimer
2. Water spraying
reversible
3. Chemical stabilization
conveyers
(BC-6B) 2 of 3
1. Shelter from wind - enclosure
stacker conveyer
2. Maintain moisture
only
(BC-6C) 3 of 3
1. Shelter from wind - enclosure
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:
1. Shelter from wind - enclosure
(BC-6)
2. Water spraying
3. Chemical stabilization
(BC-7) One
1. Shelter from wind - enclosure
conveyor to the
2. Water spraying
emergency reclaim
3. Chemical stabilization
hopper
1. Maintain moisture or visible crust
Wind Erosion:
(CS) Outdoor coal
2. Water spraying
storage piles
3. Chemical stabilization
Point Sources (Coal Handling and Storage)
PARTICULATE CONTROL DEVICES
Source (Unit ID)
Control Device
Is Control
Is there VE?
Device
Operating?
(Check one)
(Check one)
YES
NO
YES
NO
YSB-1
BC-8A & BC-8B
DC-8
BC-8A & BC-8B
screening operation
PSB-1
DE-5
BC-9A & BC-9B
BC-10A & BC-10B
CC-6A/6B &
DE-1
Silos 1A thru 1C
(coal silos)
CC-4A/4B, CC5A/5B &
DE-2
Silos 1D thru 1G
(coal silos)
Cascade Enclosure
Was EPA
Method 09
conducted?
(Check one)
YES* NO**
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
Source (Unit ID)
CC-3A/3B, CC11A/11B &
Silos 2A thru 1C
(coal silos)
CC-1A/1B, CC2A/2B &
Silos 2D thru 1G
(coal silos)
Cascade Enclosure
CC-7A/7B, CC8A/8B &
Silos 3A thru 1D
(coal silos)
CC-9A/9B &
Silos 3E thru 1G
(coal silos)
Cascade Enclosure
Source (Unit ID)
Point Sources (Coal Handling and Storage - Continued)
PARTICULATE CONTROL DEVICES
Control Device
Is Control
Is there VE?
Device
Operating?
(Check one)
(Check one)
YES
NO
YES
NO
Was EPA
Method 09
conducted?
(Check one)
YES* NO**
DE-3
DE-4
PR-2 SR-2 EX-2
DE-6
DE-7
PR-3 SR-3 EX-3
Point Sources (Fly Ash Handling and Storage)
PARTICULATE CONTROL DEVICES
Control Device
Is Control Device Is there VE?
Operating?
(Check one)
YES
NO
(Check one)
YES NO
Was EPA
Method 09
conducted?
(Check one)
YES* NO**
Silo 1 (ash silo
DC-S1/2
storage)
Silo 2 (ash silo
DC-S3
storage)
* Note: Complete one Method 9 VE Observation Form for each control device if visible emissions are
observed.
**Note: Method 9 VE Observation Form was not completed due to: Wind Direction / Sun Position / Other.
Explain:
SRP/NGS
Point Sources (Fly Ash Handling and Storage)
PARTICULATE CONTROL DEVICES
Control Device
Is Control Device
Is there VE?
Operating?
Source
(Check one)
YES
NO
(Check one)
YES NO
Was EPA
Method 09
conducted?
(Check one)
YES* NO**
Silo 1 Loading
(1 of 2 loading;
DC-S1/2
enclosed trailer
loadout)
Silo 2 Loading
(2 of 2 loading;
DC-S3
enclosed trailer
loadout)
* Note: Complete one Method 9 VE Observation Form for each control device if visible emissions are
observed.
**Note: Method 9 VE Observation Form was not completed due to: Wind Direction / Sun Position / Other.
Explain:
Non-Point Sources (Fly Ash Handling and Storage)
MATERIAL HANDLING AND ROADWAY CONTROL MEASURES
Control Measure(s) Implemented (Circle)
Comments:
1. Drop height reduction
2. Moisture retention, apply as needed
3. Wind sheltering, loading chute
Source
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
Carryout
Spillage
Unpaved Roads:
Traffic Activity
1. Drop height reduction
2. Moisture retention, apply as needed
3. Wind sheltering, loading chute
1.
2.
3.
1.
2.
3.
1.
2.
1.
2.
3.
4.
5.
Limit Traffic
Sweeping of roads
Water Flushing of roads
Clean vehicles before entering roadway
Pave access road near site exit
Rapid cleanup after event
Reducing overloaded trucks
Wetting materials being hauled
Water suppression
Chemical stabilization
Speed reduction
Limit traffic
Gravel surface
SRP/NGS
Non-Point Sources (Fly Ash Handling and Storage)
MATERIAL HANDLING AND ROADWAY CONTROL MEASURES
Source
Control Measure(s) Implemented (Circle)
Comments:
1. Enclosure
Spillage
(conveyance from
2. Rapid cleanup after spill events
post-furnace to
enclosed silos)
Non-Point Sources
PAVED ROADWAY CONTROL MEASURES
Source
Control Measure(s) Implemented (Circle)
Comments:
1. Water Spraying of Roads
Paved Roads:
2. Reduce Speed
Traffic Activity
3. Limit Traffic
4. Sweeping of roads
1. Clean vehicles before entering roadway
Carryout
2. Pave access road near site exit
3. Rapid cleanup after event
Non-Point Sources
UNPAVED ROADWAY CONTROL MEASURES
Source
Control Measure(s) Implemented (Circle)
Comments:
1. Watering
Unpaved Roads:
2. Chemical stabilization
Traffic Activity
3. Speed reduction
4. Limit traffic
5. Gravel surface
Point Sources (Soda Ash Handling and Storage)
PARTICULATE CONTROL DEVICES
Source (Unit ID)
Control Device
Is Control
Is there VE?
Was EPA
Device
Method 09
Operating?
conducted?
(Check one)
(Check one)
(Check one)
YES
NO
YES
NO
YES* NO**
SAB-1A, SAB-2A,
SAB-1B, SAB-2B
DE-BH6
(water treatment
soda ash storage
activity)
* 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
Source (Unit ID)
LB-1 & LB-2
(water treatment
lime storage
activity)
Point Sources (Lime Handling and Storage)
PARTICULATE CONTROL DEVICES
Control Device
Is Control
Is there VE?
Device
Operating?
(Check one)
(Check one)
YES
NO
YES
NO
Was EPA
Method 09
conducted?
(Check one)
YES* NO**
DE-BH7
NGS LIMESTONE WEEKLY OBSERVATIONS – 7, 10, 15 & 20% OPACTIY LIMITS
Point Sources (Limestone Handling and Storage)
PARTICULATE CONTROL DEVICES
Source (Unit ID)
Control Device (LIMT)
Is Control Device
Is there VE? Was EPA
Operating?
Method 09
conducted?
(Check one)
(Check one) (Check one)
YES
NO
YES NO YES* NO**
O-LSH-HOP-A
DC-9 (7% Opacity Limit)
O-LSH-FDR-A
O-LSH-CNV-A
O-LSH-HOP-B
DC-10 (7% Opacity Limit)
O-LSH-FDR-B
O-LSH-CNV-B
O-LSH-SILODC-11 (7% Opacity Limit)
A&B
Point and Non-Point Sources (Limestone Handling and Storage)
MATERIAL HANDLING AND STORAGE MEASURES
Source
CIRCLE Control Measures Implemented (LIMIT)
Comments:
1. Enclosures - Pt. Src. Opacity Limits: From
O-LSP-FDRbaghouses, stacks and bldg. vents/openings 7%
A&B, O-LSP2. Non-Enclosed - Fugitive Src. Opacity Limits: From
CNV-A&B
transfer pts. 10% / crushing 15%.
3. Dumping – Some activity is exempt
Limestone
1. Watering
Storage Pile (LS)
2. Maintain visible crust
* Note: Complete one Method 9 VE Observation Form for each control device if visible emissions are
observed.
**Note: Method 9 VE Observation Form was not completed due to: Wind Direction / Sun Position / Other.
Explain:
Visible Emissions Form
SRP/NGS VISIBLE EMISSION OBSERVATION FORM
Observation Date: _________________ Start Time: ______________ End Time: ___________
Process Equipment:
Limestone Handling System
Title V Condition: II.D.5.ii & II.D.6
Coal Material Handling
FIP Dust Control Plan Table 2.0
Fly Ash Handling / Storage
FIP Dust Control Plan Table 3.0
Enclosed Trailer Loading
FIP Dust Control Plan Table 7.0
Soda Ash and Lime Handling
FIP Dust Control Plan Table 9.0
LIMIT
Process Control Device* (circle):
7%
DC9 DC10 DC11 or Bldg. Vents
20%
DE1 DE2 DE3 DE4 DE5 DE6 DE7 DC8
20%
DCS1/2 DCS3
20%
DCS1/2 DCS3
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
1
2
3
4
5
6
0 second
15 sec
30 sec
45 sec
Comments
Sum of opacity readings / 24 observations =
Average opacity**
Sum of opacity readings / 24 observations =
Average opacity**
1
2
3
4
5
6
*Note: Complete one sheet for one control device with emissions.
** Note: If Average Opacity is greater than LIMIT contact Paul Ostapuk and Operations IMMEDIATELY!
Observer: ___________________
Date:________________________________________
United States Environmental Protection Agency, Region IX
Air Division
75 Hawthorne Street
San Francisco, CA 94105
ACID RAIN PERMIT
Permit Number:
NN 13-01
In accordance with the provisions of Title IV of the Clean Air Act and 40 C.F.R.
Parts 72 through 77, this Acid Rain Permit is issued to:
Salt River Project Agricultural Improvement and Power District
Navajo Generating Station (Plant Code 4941)
Page, AZ
All terms and conditions of the permit are enforceable by EPA and citizens under
the Clean Air Act. Please reference the permit number cited above in future
correspondence regarding this facility.
Date
___________________________
Deborah Jordan
Director, Air Division
EPA Region IX
Acid Rain Permit No. NN 13-01
PERMIT CONDITIONS
1. The permittee shall comply with all the applicable requirements of the Acid Rain
Permit Application located in Appendix A.
2. The Permittee shall not discharge or cause the discharge of NOx from each
pulverized coal-fired boiler (U1, U2, and U3) into the atmosphere in excess of
0.40 lb/MMBtu of heat input on an annual average basis, calculated using the
methods and procedures specified in 40 CFR Part 75, Appendix F, Section 8.
3. This Acid Rain permit incorporates the definitions of terms in 40 CFR Part 72.2.
4. This permit is valid for a term of five (5) years from the date of issuance unless a
timely and complete renewal application is submitted to EPA at the following
address:
EPA Region IX
Permits Office (AIR-3)
75 Hawthorne St.
San Francisco, CA 94105
5. A timely renewal application is an application that is received at least six months
prior to the permit expiration date.
Acid Rain Permit No. NN 13-01
Appendix A
Acid Rain Permit Application
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 SO 2 emissions limit. [40
CFR § 63.10000(c)(1)(v)]
d.
If your coal-fired EGU does not qualify as a LEE for Hg, you must demonstrate initial and
continuous compliance through use of a sorbent trap monitoring system, in accordance with
appendix A to this subpart. [40 CFR § 63.10000(c)(1)(vi)]
e.
(1)
You may choose to use separate sorbent trap monitoring systems to comply with this
subpart: One sorbent trap monitoring system to demonstrate compliance with the
numeric mercury emissions limit during periods other than startup or shutdown and the
other sorbent trap monitoring system to report average mercury concentration during
startup periods or shutdown periods.
(2)
You may choose to use one sorbent trap monitoring system to demonstrate compliance
with the mercury emissions limit at all times (including startup periods and shutdown
periods) and to report average mercury concentration. You must follow the startup or
shutdown requirements that follow and as given in Table 3 to this subpart for each coalfired, liquid oil-fired, or solid oil-derived fuel-fired EGU.
If you demonstrate compliance with any applicable emissions limit through use of a continuous
monitoring system (CMS), where a CMS includes a continuous parameter monitoring system
(CPMS) as well as a continuous emissions monitoring system (CEMS), you must develop a sitespecific monitoring plan and submit this site-specific monitoring plan, if requested, at least 60
Attachment C - Page 1 of 24
days before your initial performance evaluation (where applicable) of your CMS. This requirement
also applies to you if you petition the Administrator for alternative monitoring parameters under 40
CFR § 63.8(f). This requirement to develop and submit a site-specific monitoring plan does not
apply to affected sources with existing monitoring plans that apply to CEMS and CPMS prepared
under appendix B to part 60 or part 75 of this chapter, and that meet the requirements of 40 CFR
§ 63.10010. Using the process described in 40 CFR § 63.8(f)(4), you may request approval of
monitoring system quality assurance and quality control procedures alternative to those specified
in 40 CFR § 63.10000(d)(1) and, if approved, include those in your site-specific monitoring plan.
The monitoring plan must address the provisions in 40 CFR §§ 63.10000(d)(2) through (5). [40
CFR § 63.10000(d)(1)]
f.
If requested by the Administrator, you must submit the monitoring plan (or relevant portion of the
plan) at least 60 days before the initial performance evaluation of a particular CMS, except where
the CMS has already undergone a performance evaluation that meets the requirements of 40
CFR § 63.10010 (e.g., if the CMS was previously certified under another program). [40 CFR §
63.10000(d)(3)]
g.
You must operate and maintain the CMS according to the site-specific monitoring plan. [40 CFR §
63.10000(d)(4)]
h.
The provisions of the site-specific monitoring plan must address the following items: [40 CFR §
63.10000(d)(5)]
i.
(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.
As part of your demonstration of continuous compliance, you must perform periodic tune-ups of
your EGU(s), according to 40 CFR § 63.10021(e). [40 CFR § 63.10000(e)]
Attachment C - Page 2 of 24
II. TESTING AND INITIAL COMPLIANCE REQUIREMENTS
a.
For each of your affected EGUs, you must demonstrate initial compliance with each applicable
emissions limit through performance testing. Where two emissions limits are specified for a
particular pollutant (e.g., a heat input-based limit in lb/MMBtu and an electrical output-based limit
in lb/MWh), you may demonstrate compliance with either emission limit. For a particular
compliance demonstration, you may be required to conduct one or more of the following activities
in conjunction with performance testing: collection of hourly electrical load data (megawatts);
establishment of operating limits according to 40 CFR § 63.10011 and Tables 4 and 7 to Subpart
UUUUU; and CMS performance evaluations. In all cases, you must demonstrate initial
compliance no later than the applicable date in 40 CFR § 63.10005(f) for tune-up work practices
for existing EGUs, in 40 CFR § 63.9984 for other requirements for existing EGUs, and in 40 CFR
§ 63.10005(g) for all requirements for new EGUs. [40 CFR § 63.10005(a)]
b.
To demonstrate initial compliance using either a CMS that measures HAP concentrations directly
(i.e., an Hg, HCl, or HF CEMS, or a sorbent trap monitoring system) or an SO 2 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 SO 2 emissions limit in
Table 1 or 2 to 40 CFR 63, Subpart UUUUU.
(2)
You must collect hourly data from auxiliary monitoring systems (i.e., stack gas flow rate,
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 SO 2 emissions limit in Table 2 to this
subpart through use of an SO2 CEMS installed and operated in accordance with part 75 of this
chapter or appendix B to this subpart, as applicable. You may also demonstrate compliance with
a filterable PM emission limit in Table 2 to this subpart through use of a PM CEMS installed,
certified, and operated in accordance with 40 CFR § 63.10010(i). Initial compliance is achieved if
the arithmetic average of 30-boiler operating days of quality-assured CEMS data, expressed in
units of the standard (see 40 CFR § 63.10007(e)), meets the applicable SO2 or PM emissions
limit in Table 2 to this subpart. Use Equation 19-19 of Method 19 in appendix A-7 to part 60 of this
chapter to calculate the 30-boiler operating day average emissions rate. [40 CFR §
63.10005(d)(1)]
Attachment C - Page 3 of 24
e.
For affected EGUs that are either required to or elect to demonstrate initial compliance with the
applicable Hg emission limit in Table 2 of this subpart using sorbent trap monitoring systems,
initial compliance must be demonstrated no later than the applicable date specified in 40 CFR §
63.9984(f) for existing EGUs. Initial compliance is achieved if the arithmetic average of 30-boiler
operating days of quality-assured sorbent trap monitoring system data, expressed in units of the
standard (see section 6.2 of appendix A to this subpart), meets the applicable Hg emission limit in
Table 2 to this subpart. [40 CFR § 63.10005(d)(3)]
f.
All affected EGUs are subject to the work practice standards in Table 3 of 40 CFR Part 63,
Subpart UUUUU. As part of your initial compliance demonstration, you must conduct a
performance tune-up of your EGU according to 40 CFR § 63.10021(e). [40 CFR § 63.10005(e)]
g.
For existing affected sources a tune-up may occur prior to April 16, 2012, so that existing sources
employing neural network combustion controls, up to 54 calendar months (48 months from
promulgation plus 180 days) after the date that is specified for your source in 40 CFR § 63.9984
and according to the applicable provisions in 40 CFR § 63.7(a)(2) as cited in Table 9 to this
subpart to demonstrate compliance with this requirement. If a tune-up occurs prior to such date,
the source must maintain adequate records to show that the tune-up met the requirements of this
standard. [40 CFR § 63.10005(f)]
h.
You must follow the startup and shutdown requirements given in Table 3 of 40 CFR Part 63,
Subpart UUUUU. [40 CFR § 63.10005(j)]
i.
You must submit a Notification of Compliance Status summarizing the results of your initial
compliance demonstration, as provided in 40 CFR § 63.10030. [40 CFR § 63.10005(k)]
Subsequent performance tests and tune-ups
j.
If you are required to meet an applicable tune-up work practice standard, you must conduct a
performance tune-up according to 40 CFR § 63.10021(e). For EGUs employing neural network
combustion optimization systems during normal operation, each performance tune-up specified in
40 CFR § 63.10021(e) must be no more than 48 calendar months after the previous performance
tune-up. [40 CFR § 63.10006(i)(2)]
k.
You must report the results of performance tests and performance tune-ups within 60 days after
the completion of the performance tests and performance tune-ups. The reports for all
subsequent performance tests must include all applicable information required in 40 CFR §
63.10031. [40 CFR § 63.10006(j)]
Methods and other procedures for the performance tests
l.
Except as otherwise provided in this section, you must conduct all required performance tests
according to 40 CFR §§ 63.7(d), (e), (f), and (h). You must also develop a site-specific test plan
according to the requirements in 40 CFR § 63.7(c). [40 CFR § 63.10007(a)]
m.
If you use CEMS (Hg, HCl, SO2, or other) to determine compliance with a 30- (or, if applicable,
90-) boiler operating day rolling average emission limit, you must collect quality- assured CEMS
data for all unit operating conditions, including startup and shutdown (see 40 CFR § 63.10011(g)
and Table 3 to 40 CFR 63, Subpart UUUUU), except as otherwise provided in 40 CFR §
63.10020(b). Emission rates determined during startup periods and shutdown periods (as defined
in 40 CFR § 63.10042) are not to be included in the compliance determinations, except as
otherwise provided in 40 CFR §§ 63.10000(c)(1)(vi)(B) and 63.10005(a)(2)(iii). [40 CFR §
63.10007(a)(1)]
Attachment C - Page 4 of 24
n.
You must conduct each performance test (including traditional 3-run stack tests, 30-boiler
operating day tests based on CEMS data (or sorbent trap monitoring system data), and 30-boiler
operating day Hg emission tests for LEE qualification) according to the requirements in Table 5 to
Subpart UUUUU. [40 CFR § 63.10007(b)]
o.
To use the results of performance testing to determine compliance with the applicable emission
limits in Table 2 to Subpart UUUUU, proceed as follows: [40 CFR § 63.10007(e)]
(1)
Except for a 30-boiler operating day performance test based on CEMS (or sorbent trap
monitoring system) data, if measurement results for any pollutant are reported as below
the method detection level (e.g., laboratory analytical results for one or more sample
components are below the method defined analytical detection level), you must use the
method detection level as the measured emissions level for that pollutant in calculating
compliance. The measured result for a multiple component analysis (e.g., analytical
values for multiple Method 29 fractions both for individual HAP metals and for total HAP
metals) may include a combination of method detection level data and analytical data
reported above the method detection level.
(2)
If the limits are expressed in lb/MMBtu or lb/TBtu, you must use the F-factor methodology
and equations in sections 12.2 and 12.3 of EPA Method 19 in appendix A-7 to part 60 of
this chapter. In cases where an appropriate F-factor is not listed in Table 19-2 of Method
19, you may use F-factors from Table 1 in section 3.3.5 of appendix F to part 75 of this
chapter, or F-factors derived using the procedures in section 3.3.6 of appendix to part 75
of this chapter. Use the following factors to convert the pollutant concentrations
measured during the initial performance tests to units of lb/scf, for use in the applicable
Method 19 equations:
(3)
p.
(i)
Multiply SO2 ppm by 1.66 × 10−7;
(ii)
Multiply Hg concentrations (µg/scm) by 6.24 × 10−11.
To determine compliance with emission limits expressed in lb/MWh or lb/GWh, you must
first calculate the pollutant mass emission rate during the performance test, in units of
lb/h. For Hg, if a CEMS or sorbent trap monitoring system is used, use Equation A-2 or A3 in appendix A to this subpart (as applicable). In all other cases, use an equation that
has the general form of Equation A-2 or A-3, replacing the value of K with 1.66 × 10−7
lb/scf-ppm for SO2, 9.43 × 10−8 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 C h 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.
If you elect to (or are required to) use CEMS to continuously monitor Hg, HCl, HF, SO 2, or PM
emissions (or, if applicable, sorbent trap monitoring systems to continuously collect Hg emissions
data), the following default values are available for use in the emission rate calculations during
startup periods or shutdown periods (as defined in 40 CFR § 63.10042). For the purposes of this
subpart, these default values are not considered to be substitute data. [40 CFR § 63.10007(f)]
Attachment C - Page 5 of 24
(1)
(2)
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 CO 2 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.
Default electrical load. If you use CEMS to continuously monitor Hg, HCl, HF, SO 2, or PM
emissions (or, if applicable, sorbent trap monitoring systems to continuously collect Hg
emissions data), the following default value is available for use in the 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 SO 2 or
Attachment C - Page 6 of 24
filterable PM emission limit in Table 2 to 40 CFR Part 63, Subpart UUUUUU. [40 CFR §
63.10011(c)(2)]
w.
You must submit a Notification of Compliance Status containing the results of the initial
compliance demonstration, according to 40 CFR § 63.10030(e). [40 CFR § 63.10011(e)]
x.
You must determine the fuel whose combustion produces the least uncontrolled emissions, i.e.,
the cleanest fuel, either natural gas or distillate oil, that is available on site or accessible nearby
for use during periods of startup or shutdown. [40 CFR § 63.10011(f)(1)]
y.
Your cleanest fuel, either natural gas or distillate oil, for use during periods of startup or shutdown
determination may take safety considerations into account. [40 CFR § 63.10011(f)(2)]
z.
You must follow the startup or shutdown requirements as given in Table 3 to subpart UUUUU for
each coal-fired EGU. [40 CFR § 63.10011(g)]
(1)
You may use the diluent cap and default electrical load values, as described in 40 CFR §
63.10007(f), during startup periods or shutdown periods.
(2)
You must operate all CMS, collect data, calculate pollutant emission rates, and record
data during startup periods or shutdown periods.
(3)
You must report the information as required in 40 CFR § 63.10031.
(4)
If you choose to use paragraph (2) of the definition of “startup” in 40 CFR § 63.10042 and
you find that you are unable to safely engage and operate your particulate matter (PM)
control(s) within 1 hour of first firing of coal, you may choose to rely on paragraph (1) of
definition of “startup” in 40 CFR § 63.10042 or you may submit a request to use an
alternative non-opacity emissions standard, as described below.
(i)
As mentioned in 40 CFR § 63.6(g)(1), the request will be published in the Federal
Register for notice and comment rulemaking. Until promulgation in the Federal
Register of the final alternative non-opacity emission standard, you shall comply
with paragraph (1) of the definition of “startup” in 40 CFR § 63.10042. You shall
not implement the alternative non-opacity emissions standard until promulgation
in the Federal Register of the final alternative non-opacity emission standard.
(ii)
The request need not address the items contained in 40 CFR § 63.6(g)(2).
(iii)
The request shall provide evidence of a documented manufacturer-identified
safely issue.
(iv)
The request shall provide information to document that the PM control device is
adequately designed and sized to meet the PM emission limit applicable to the
EGU.
(v)
In addition, the request shall contain documentation that:
(A)
The EGU is using clean fuels to the maximum extent possible to bring
the EGU and PM control device up to the temperature necessary to
alleviate or prevent the identified safety issues prior to the combustion of
primary fuel in the EGU;
Attachment C - Page 7 of 24
(B)
The EGU has explicitly followed the manufacturer's procedures to
alleviate or prevent the identified safety issue; and
(C)
Identifies with specificity the details of the manufacturer's statement of
concern.
(vi)
The request shall specify the other work practice standards the EGU owner or
operator will take to limit HAP emissions during startup periods and shutdown
periods to ensure a control level consistent with the work practice standards of
the final rule.
(vii)
You must comply with all other work practice requirements, including but not
limited to data collection, recordkeeping, and reporting requirements.
III. CONTINUOUS COMPLIANCE REQUIREMENTS
General compliance requirements
a.
You must monitor and collect data according to this section and the site-specific monitoring plan
required by 40 CFR § 63.10000(d). [40 CFR § 63.10020(a)]
b.
You must operate the monitoring system and collect data at all required intervals at all times that
the affected EGU is operating, except for periods of monitoring system malfunctions or out-ofcontrol periods (see 40 CFR § 63.8(c)(7) of this part), and required monitoring system quality
assurance or quality control activities, including, as applicable, calibration checks and required
zero and span adjustments. You are required to affect monitoring system repairs in response to
monitoring system malfunctions and to return the monitoring system to operation as expeditiously
as practicable. [40 CFR § 63.10020(b)]
c.
You may not use data recorded during EGU startup or shutdown in calculations used to report
emissions, except as otherwise provided in 40 CFR §§ 63.10000(c)(1)(vi)(B) and
63.10005(a)(2)(iii). In addition, data recorded during monitoring system malfunctions or
monitoring system out-of-control periods, repairs associated with monitoring system malfunctions
or monitoring system out-of-control periods, or required monitoring system quality assurance or
control activities may not be used in calculations used to report emissions or operating levels.
You must use all of the quality-assured data collected during all other periods in assessing the
operation of the control device and associated control system. [40 CFR § 63.10020(c)]
d.
Except for periods of monitoring system malfunctions or monitoring system out-of-control periods,
repairs associated with monitoring system malfunctions or monitoring system out-of-control
periods, and required monitoring system quality assurance or quality control activities including,
as applicable, calibration checks and required zero and span adjustments), failure to collect
required data is a deviation from the monitoring requirements. [40 CFR § 63.10020(d)]
e.
During each period of startup, you must record the following for each EGU: [40 CFR §
63.10020(e)(1)]
(1)
The date and time that clean fuels being combusted for the purpose of startup begins;
(2)
The quantity and heat input of clean fuel for each hour of startup;
(3)
The electrical load for each hour of startup;
Attachment C - Page 8 of 24
f.
g.
(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.
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.
For PM or non-mercury HAP metals work practice monitoring during startup periods, you must
monitor and collect data according to 40 CFR § 63.10020 and the site-specific monitoring plan
required by 40 CFR § 63.10011(l). [40 CFR § 63.10020(e)(3)]
Continuous compliance with the emission limitations, operating limits, and work practice
standards
h.
You must demonstrate continuous compliance with each emissions limit, operating limit, and work
practice standard according to the monitoring specified in Table 7 to Subpart UUUUU and 40
CFR § 63.10021(b) through (g). [40 CFR § 63.10021(a)]
i.
Except as otherwise provided in 40 CFR § 63.10020(c), if you use a CEMS to measure SO2, PM,
HCl, HF, or Hg emissions, or using a sorbent trap monitoring system to measure Hg emissions,
you must demonstrate continuous compliance by using all quality-assured hourly data recorded
by the CEMS (or sorbent trap monitoring system) and the other required monitoring systems
(e.g., flow rate, CO2, O2, or moisture systems) to calculate the arithmetic average emissions rate
in units of the standard on a continuous 30-boiler operating day (or, if alternate emissions
averaging is used for Hg, 90-boiler operating day) rolling average basis, updated at the end of
each new boiler operating day. Use Equation 8 to determine the 30- (or, if applicable, 90-) boiler
operating day rolling average. [40 CFR § 63.10021(b)]
Where:
Heri is the hourly emissions rate for hour i and n is the number of hourly emissions rate values collected over
30- (or, if applicable, 90-) boiler operating days.
j.
If you must conduct periodic performance tune-ups of your EGU(s) as specified below and
perform the first tune-up as part of your initial compliance demonstration. Notwithstanding this
requirement, you may delay the first burner inspection until the next scheduled unit outage
provided you meet the requirements of 40 CFR § 63.10005. Subsequently, you must perform an
inspection of the burner at least once every 36 calendar months unless your EGU employs neural
network combustion optimization during normal operations in which case you must perform an
Attachment C - Page 9 of 24
inspection of the burner and combustion controls at least once every 48 calendar months. [40
CFR § 63.10021(e)]
(1)
As applicable, inspect the burner and combustion controls, and clean or replace any
components of the burner or combustion controls as necessary upon initiation of the work
practice program and at least once every required inspection period. Repair of a burner
or combustion control component requiring special order parts may be scheduled as
follows:
(i)
Burner or combustion control component parts needing replacement that affect
the ability to optimize NOX and CO must be installed within 3 calendar months
after the burner inspection,
(ii)
Burner or combustion control component parts that do not affect the ability to
optimize NOX and CO may be installed on a schedule determined by the
operator;
(2)
As applicable, inspect the flame pattern and make any adjustments to the burner or
combustion controls necessary to optimize the flame pattern. The adjustment should be
consistent with the manufacturer's specifications, if available, or in accordance with best
combustion engineering practice for that burner type;
(3)
As applicable, observe the damper operations as a function of mill and/or cyclone
loadings, cyclone and pulverizer coal feeder loadings, or other pulverizer and coal mill
performance parameters, making adjustments and effecting repair to dampers, controls,
mills, pulverizers, cyclones, and sensors;
(4)
As applicable, evaluate windbox pressures and air proportions, making adjustments and
effecting repair to dampers, actuators, controls, and sensors;
(5)
Inspect the system controlling the air-to-fuel ratio and ensure that it is correctly calibrated
and functioning properly. Such inspection may include calibrating excess O 2 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. NO X optimization includes burners,
overfire air controls, concentric firing system improvements, neural network or
combustion efficiency software, control systems calibrations, adjusting combustion zone
temperature profiles, and add-on controls such as SCR and SNCR; CO optimization
includes burners, overfire air controls, concentric firing system improvements, neural
network or combustion efficiency software, control systems calibrations, and adjusting
combustion zone temperature profiles;
(7)
While operating at full load or the predominantly operated load, measure the
concentration in the effluent stream of CO and NOX in ppm, by volume, and oxygen in
volume percent, before and after the tune-up adjustments are made (measurements may
be either on a dry or wet basis, as long as it is the same basis before and after the
adjustments are made). You may use portable CO, NOX and O2 monitors for this
measurement. EGU's employing neural network optimization systems need only provide
Attachment C - Page 10 of 24
a single pre- and post-tune-up value rather than continual values before and after each
optimization adjustment made by the system;
(8)
(9)
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
Report the dates of the initial and subsequent tune-ups as follows:
(i)
If the first required tune-up is performed as part of the initial compliance
demonstration, report the date of the tune-up in hard copy (as specified in 40
CFR § 63.10030) and electronically (as specified in 40 CFR § 63.10031). Report
the date of each subsequent tune-up electronically (as specified in 40 CFR §
63.10031).
(ii)
If the first tune-up is not conducted as part of the initial compliance
demonstration, but is postponed until the next unit outage, report the date of that
tune-up and all subsequent tune-ups electronically, in accordance with 40 CFR §
63.10031.
k.
You must submit the reports required under 40 CFR § 63.10031 and, if applicable, the reports
required under appendices A and B to Subpart UUUUU. The electronic reports required by
appendices A and B to Subpart UUUUU must be sent to the Administrator electronically in a
format prescribed by the Administrator, as provided in 40 CFR § 63.10031. CEMS data (except
for PM CEMS and any approved alternative monitoring using a HAP metals CEMS) shall be
submitted using EPA's Emissions Collection and Monitoring Plan System (ECMPS) Client Tool.
Other data, including PM CEMS data, HAP metals CEMS data, and CEMS performance test
detail reports, shall be submitted in the file format generated through use of EPA's Electronic
Reporting Tool, the Compliance and Emissions Data Reporting Interface, or alternate electronic
file format, all as provided for under 40 CFR § 63.10031. [40 CFR § 63.10021(f)]
l.
You must report each instance in which you did not meet an applicable emissions limit or
operating limit or failed to conduct a required tune-up. These instances are deviations from the
requirements of Subpart UUUUU. These deviations must be reported according to 40 CFR §
63.10031. [40 CFR § 63.10021(g)]
m.
You must follow the startup or shutdown requirements as given in Table 3 to subpart UUUUU. [40
CFR § 63.10021(h)]
(1)
You may use the diluent cap and default electrical load values, as described in 40 CFR §
63.10007(f), during startup periods or shutdown periods.
Attachment C - Page 11 of 24
n.
(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.
You must provide reports as specified in 40 CFR § 63.10031 concerning activities and periods of
startup and shutdown. [40 CFR § 63.10021(i)]
Demonstrate continuous compliance under the emissions averaging provision
o.
If the permittee elects to demonstrate compliance under the emissions averaging provision, the
permittee must demonstrate compliance with this subpart on a continuous basis by meeting the
requirements of 40 CFR §§ 63.1022(a)(1), (a)(4), and (b). [40 CFR § 63.10022]
IV. NOTIFICATION, REPORTS, AND RECORDS
Notifications Requirements
a.
You must submit all of the notifications in §40 CFR § 63.7(b) and (c), 63.8 (e), (f)(4) and (6), and
63.9 (b) through (h) that apply to you by the dates specified. [40 CFR § 63.10030(a)]
b.
When you are required to conduct a performance test, you must submit a Notification of Intent to
conduct a performance test at least 30 days before the performance test is scheduled to begin.
[40 CFR § 63.10030(d)]
c.
When you are required to conduct an initial compliance demonstration as specified in 40 CFR §
63.10011(a), you must submit a Notification of Compliance Status according to 40 CFR §
63.9(h)(2)(ii). The Notification of Compliance Status report must contain all the information
specified in 40 CFR § 63.10030(e)(1) through (8), as applicable. [40 CFR § 63.10030(e)]
(1)
A description of the affected source(s) including identification of which subcategory the
source is in, the design capacity of the source, a description of the add-on controls used
on the source, description of the fuel(s) burned, including whether the fuel(s) were
determined by you or EPA through a petition process to be a non-waste under 40 CFR
241.3, whether the fuel(s) were processed from discarded non-hazardous secondary
materials within the meaning of 40 CFR 241.3, and justification for the selection of fuel(s)
burned during the performance test.
(2)
Summary of the results of all performance tests and fuel analyses and calculations
conducted to demonstrate initial compliance including all established operating limits.
(3)
Identification of whether you plan to demonstrate compliance with each applicable
emission limit through performance testing; fuel moisture analyses; performance testing
with operating limits (e.g., use of PM CPMS); CEMS; or a sorbent trap monitoring
system.
(4)
Identification of whether you plan to demonstrate compliance by emissions averaging.
Attachment C - Page 12 of 24
(5)
A signed certification that you have met all applicable emission limits and work practice
standards.
(6)
If you had a deviation from any emission limit, work practice standard, or operating limit,
you must also submit a brief description of the deviation, the duration of the deviation,
emissions point identification, and the cause of the deviation in the Notification of
Compliance Status report.
(7)
In addition to the information required in 40 CFR § 63.9(h)(2), your notification of
compliance status must include the following:
(8)
(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.”
Identification of whether you plan to rely on paragraph (1) or (2) of the definition of
“startup” in 40 CFR § 63.10042.
(i)
Should you choose to rely on paragraph (2) of the definition of “startup” in 40
CFR § 63.10042 for your EGU, you shall include a report that identifies:
(A)
The original EGU installation date;
(B)
The original EGU design characteristics, including, but not limited to, fuel
and PM controls;
(C)
Each design PM control device efficiency;
(D)
The design PM emission rate from the EGU in terms of pounds PM per
MMBtu and pounds PM per hour;
(E)
The design time from start of fuel combustion to necessary conditions for
each PM control device startup;
(F)
Each design PM control device efficiency upon startup of the PM control
device;
(G)
The design EGU uncontrolled PM emission rate in terms of pounds PM
per hour;
Attachment C - Page 13 of 24
(ii)
(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.
The report shall be prepared, signed, and sealed by a professional engineer
licensed in the state where your EGU is located. Apart from preparing, signing,
and sealing this report, the professional engineer shall be independent and not
otherwise employed by your company, any parent company of your company, or
any subsidiary of your company.
Reporting Requirements
d.
You must submit each report in Table 8 to Subpart UUUUU that applies to you. If you are
required to (or elect to) continuously monitor Hg and/or HCl and/or HF emissions, you must also
submit the electronic reports required under appendix A and/or appendix B to the subpart, at the
specified frequency. [40 CFR § 63.10031(a)]
e.
Unless the Administrator has approved a different schedule for submission of reports under 40
CFR § 63.10(a), you must submit each report by the date in Table 8 to Subpart UUUUU and
according to the requirements specified below: [40 CFR § 63.10031(b)]
(1)
The first compliance report must cover the period beginning on the compliance date that
is specified for your affected source in 40 CFR § 63.9984 and ending on June 30 or
December 31, whichever date is the first date that occurs at least 180 days after the
compliance date that is specified for your source in 40 CFR § 63.9984.
(2)
The first compliance report must be postmarked or submitted electronically no later than
July 31 or January 31, whichever date is the first date following the end of the first
calendar half after the compliance date that is specified for your source in 40 CFR §
63.9984.
(3)
Each subsequent compliance report must cover the semiannual reporting period from
January 1 through June 30 or the semiannual reporting period from July 1 through
December 31.
Attachment C - Page 14 of 24
f.
g.
(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.
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.
For each excess emissions occurring at an affected source where you are using a CMS to
comply with that emission limit or operating limit, you must include the information required in 40
Attachment C - Page 15 of 24
CFR § 63.10(e)(3)(v) in the compliance report specified 40 CFR § 63.10031(c). [40 CFR §
63.10031(d)]
h.
You must report all deviations as defined in Subpart UUUUU in the semiannual monitoring report
required by 40 CFR 70.6(a)(3)(iii)(A) or 40 CFR 71.6(a)(3)(iii)(A). If an affected source submits a
compliance report pursuant to Table 8 to Subpart UUUUU along with, or as part of, the
semiannual monitoring report required by 40 CFR 70.6(a)(3)(iii)(A) or 40 CFR 71.6(a)(3)(iii)(A),
and the compliance report includes all required information concerning deviations from any
emission limit, operating limit, or work practice requirement in Subpart UUUUU, submission of the
compliance report satisfies any obligation to report the same deviations in the semiannual
monitoring report. Submission of a compliance report does not otherwise affect any obligation the
affected source may have to report deviations from permit requirements to the permit authority.
[40 CFR § 63.10031(e)]
i.
On or after April 16, 2017, within 60 days after the date of completing each performance test, you
must submit the performance test reports required by this subpart to EPA's WebFIRE database
by using the Compliance and Emissions Data Reporting Interface (CEDRI) that is accessed
through EPA's Central Data Exchange (CDX) (www.epa.gov/cdx). Performance test data must be
submitted in the file format generated through use of EPA's Electronic Reporting Tool (ERT) (see
http://www.epa.gov/ttn/chief/ert/index.html). Only data collected using those test methods on the
ERT Web site are subject to this requirement for submitting reports electronically to WebFIRE.
Owners or operators who claim that some of the information being submitted for performance
tests is confidential business information (CBI) must submit a complete ERT file including
information claimed to be CBI on a compact disk or other commonly used electronic storage
media (including, but not limited to, flash drives) to EPA. The electronic media must be clearly
marked as CBI and mailed to U.S. EPA/OAPQS/CORE CBI Office, Attention: WebFIRE
Administrator, MD C404-02, 4930 Old Page Rd., Durham, NC 27703. The same ERT file with the
CBI omitted must be submitted to EPA via CDX as described earlier in this paragraph. At the
discretion of the delegated authority, you must also submit these reports, including the
confidential business information, to the delegated authority in the format specified by the
delegated authority. [40 CFR § 63.10031(f)]
(1)
On or after April 16, 2017, within 60 days after the date of completing each CEMS (SO 2,
PM, HCl, HF, and Hg) performance evaluation test, as defined in 40 CFR § 63.2 and
required by this subpart, you must submit the relative accuracy test audit (RATA) data
(or, for PM CEMS, RCA and RRA data) required by this subpart to EPA's WebFIRE
database by using CEDRI that is accessed through EPA's CDX (www.epa.gov/cdx). The
RATA data shall be submitted in the file format generated through use of EPA's
Electronic Reporting Tool (ERT) (http://www.epa.gov/ttn/chief/ert/index.html). Only RATA
data compounds listed on the ERT Web site are subject to this requirement. Owners or
operators who claim that some of the information being submitted for RATAs is
confidential business information (CBI) shall submit a complete ERT file including
information claimed to be CBI on a compact disk or other commonly used electronic
storage media (including, but not limited to, flash drives) by registered letter to EPA and
the same ERT file with the CBI omitted to EPA via CDX as described earlier in this
paragraph. The compact disk or other commonly used electronic storage media shall be
clearly marked as CBI and mailed to U.S. EPA/OAPQS/CORE CBI Office, Attention:
WebFIRE Administrator, MD C404-02, 4930 Old Page Rd., Durham, NC 27703. At the
discretion of the delegated authority, owners or operators shall also submit these RATAs
to the delegated authority in the format specified by the delegated authority. Owners or
operators shall submit calibration error testing, drift checks, and other information
required in the performance evaluation as described in 40 CFR § 63.2 and as required in
this chapter.
Attachment C - Page 16 of 24
(2)
On or after April 16, 2017, for a PM CEMS, PM CPMS, or approved alternative
monitoring using a HAP metals CEMS, within 60 days after the reporting periods ending
on March 31st, June 30th, September 30th, and December 31st, you must submit
quarterly reports to EPA's WebFIRE database by using the CEDRI that is accessed
through EPA's CDX (www.epa.gov/cdx). You must use the appropriate electronic
reporting form in CEDRI or provide an alternate electronic file consistent with EPA's
reporting form output format. For each reporting period, the quarterly reports must include
all of the calculated 30-boiler operating day rolling average values derived from the
CEMS and PM CPMS.
(3)
On or after April 16, 2017, submit the compliance reports required under 40 CFR §
63.10031(c) and (d) and the notification of compliance status required under 40 CFR §
63.10030(e) to EPA’s WebFIRE database by using the CEDRI that is accessed through
EPA’s CDX (www.epa.gov/cdx). You must use the appropriate electronic reporting form
in CEDRI or provide an alternate electronic file consistent with EPA's reporting form
output format.
(4)
On or after April 16, 2017, submit the compliance reports required under 40 CFR §
63.10031(c) and (d) and the notification of compliance status required under 40 CFR §
63.10030(e) to EPA's WebFIRE database by using the CEDRI that is accessed through
EPA's CDX (www.epa.gov/cdx). You must use the appropriate electronic reporting form
in CEDRI or provide an alternate electronic file consistent with EPA's reporting form
output format.
(5)
All reports required by this subpart not subject to the requirements in 40 CFR §
63.10030(f) introductory text and 40 CFR § 63.10031(f)(1) through (4) must be sent to the
Administrator at the appropriate address listed in 40 CFR § 63.13. If acceptable to both
the Administrator and the owner or operator of an EGU, these reports may be submitted
on electronic media. The Administrator retains the right to require submittal of reports
subject to 40 CFR § 63.10030(f) introductory text and 40 CFR § 63.10031(f)(1) through
(4) in paper format.
(6)
Prior to April 16, 2017, all reports subject to electronic submittal in 40 CFR § 63.10031(f)
(f) introductory text, (f)(1), (2), and (4) shall be submitted to the EPA at the frequency
specified in those paragraphs in electronic portable document format (PDF) using the
ECMPS Client Tool. Each PDF version of a submitted report must include sufficient
information to assess compliance and to demonstrate that the testing was done properly.
The following data elements must be entered into the ECMPS Client Tool at the time of
submission of each PDF file:
(i)
The facility name, physical address, mailing address (if different from the physical
address), and county;
(ii)
The ORIS code (or equivalent ID number assigned by EPA's Clean Air Markets
Division (CAMD)) and the Facility Registry System (FRS) ID;
(iii)
The EGU (or EGUs) to which the report applies. Report the EGU IDs as they
appear in the CAMD Business System;
(iv)
If any of the EGUs in 40 CFR § 63.10031(f)(6)(iii) share a common stack,
indicate which EGUs share the stack. If emissions data are monitored and
reported at the common stack according to part 75 of this chapter, report the ID
number of the common stack as it is represented in the electronic monitoring
plan required under 40 CFR § 75.53 of this chapter;
Attachment C - Page 17 of 24
j.
(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.
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.
l.
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).
For each CEMS, you must keep records according to the following: [40 CFR § 63.10032(b)]
(1)
Records described in 40 CFR § 63.10(b)(2)(vi) through (xi).
(2)
Previous (i.e., superseded) versions of the performance evaluation plan as required in 40
CFR § 63.8(d)(3).
Attachment C - Page 18 of 24
(3)
Request for alternatives to relative accuracy test for CEMS as required in 40 CFR §
63.8(f)(6)(i).
(4)
Records of the date and time that each deviation started and stopped, and whether the
deviation occurred during a period of startup, shutdown, or malfunction or during another
period.
m.
You must keep the records required in Table 7 to Subpart UUUUU including records of all
monitoring data to show continuous compliance with each emission limit and operating limit that
applies to you. [40 CFR § 63.10032(c)]
n.
For each EGU subject to an emission limit, you must also keep the records specified below: [40
CFR § 63.10032(d)]
(1)
You must keep records of monthly fuel use by each EGU, including the type(s) of fuel
and amount(s) used.
(2)
If you combust non-hazardous secondary materials that have been determined not to be
solid waste pursuant to 40 CFR 241.3(b)(1), you must keep a record which documents
how the secondary material meets each of the legitimacy criteria. If you combust a fuel
that has been processed from a discarded non-hazardous secondary material pursuant
to 40 CFR 241.3(b)(2), you must keep records as to how the operations that produced
the fuel satisfies the definition of processing in 40 CFR 241.2. If the fuel received a nonwaste determination pursuant to the petition process submitted under 40 CFR 241.3(c),
you must keep a record which documents how the fuel satisfies the requirements of the
petition process.
(3)
For an EGU that qualifies as an LEE under 40 CFR § 63.10005(h), you must keep annual
records that document that your emissions in the previous stack test(s) continue to
qualify the unit for LEE status for an applicable pollutant, and document that there was no
change in source operations including fuel composition and operation of air pollution
control equipment that would cause emissions of the pollutant to increase within the past
year.
o.
If you elect to average emissions consistent with 40 CFR § 63.10009, you must additionally keep
a copy of the emissions averaging implementation plan required in 40 CFR § 63.10009(g), all
calculations required under 40 CFR § 63.10009, including daily records of heat input or steam
generation, as applicable, and monitoring records consistent with 40 CFR § 63.10022. [40 CFR §
63.10032(e)]
p.
You must keep the following records for each startup and/or shutdown: [40 CFR § 63.10032(f)]
q.
(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).
You must keep records of the occurrence and duration of each malfunction of an operation (i.e.,
process equipment) or the air pollution control and monitoring equipment. [40 CFR § 63.10032(g)]
Attachment C - Page 19 of 24
r.
You must keep records of actions taken during periods of malfunction to minimize emissions in
accordance with 40 CFR § 63.10000(b), including corrective actions to restore malfunctioning
process and air pollution control and monitoring equipment to its normal or usual manner of
operation. [40 CFR § 63.10032(h)]
s.
You must keep records of the type(s) and amount(s) of fuel used during each startup or
shutdown. [40 CFR § 63.10032(i)]
t.
Your records must be in a form suitable and readily available for expeditious review, according to
40 CFR § 63.10(b)(1). [40 CFR § 63.10033(a)]
u.
As specified in 40 CFR § 63.10(b)(1), you must keep each record for 5 years following the date of
each occurrence, measurement, maintenance, corrective action, report, or record. [40 CFR §
63.10033(b)]
v.
You must keep each record on site for at least 2 years after the date of each occurrence,
measurement, maintenance, corrective action, report, or record, according to 40 CFR §
63.10(b)(1). You can keep the records off site for the remaining 3 years. [40 CFR § 63.10033(c)]
TABLES TO SUBPART UUUUU OF PART 63
Table 3 to Subpart UUUUU of Part 63—Work Practice Standards
As stated in §40 CFR § 63.9991, you must comply with the following applicable work practice
standards:
If your EGU is . . .
You must meet the following . . .
1. An existing EGU
Conduct a tune-up of the EGU burner and combustion controls at least each 36
calendar months, or each 48 calendar months if neural network combustion
optimization software is employed, as specified in 40 CFR § 63.10021(e).
3. A coal-fired, liquid If you choose to comply using paragraph (1) of the definition of “startup” in 40 CFR
oil-fired, or solid oil- § 63.10042, you must operate all CMS during startup. Startup means either the
derived fuel-fired EGU first-ever firing of fuel in a boiler for the purpose of producing electricity, or the
during startup
firing of fuel in a boiler after a shutdown event for any purpose. Startup ends when
any of the steam from the boiler is used to generate electricity for sale over the
grid or for any other purpose (including on site use). For startup of a unit, you must
use clean fuels as defined in 40 CFR § 63.10042 for ignition. Once you convert to
firing coal, residual oil, or solid oil-derived fuel, you must engage all of the
applicable control technologies except dry scrubber and SCR. You must start your
dry scrubber and SCR systems, if present, appropriately to comply with relevant
standards applicable during normal operation. You must comply with all applicable
emissions limits at all times except for periods that meet the applicable definitions
of startup and shutdown in this subpart. You must keep records during startup
periods. You must provide reports concerning activities and startup periods, as
specified in 40 CFR § 63.10011(g) and 40 CFR § 63.10021(h) and (i).
For startup of an EGU, you must use one or a combination of the clean fuels
defined in 40 CFR § 63.10042 to the maximum extent possible throughout the
startup period. You must have sufficient clean fuel capacity to engage and operate
your PM control device within one hour of adding coal, residual oil, or solid oilderived fuel to the unit. You must meet the startup period work practice
requirements as identified in 40 CFR § 63.10020(e).
Attachment C - Page 20 of 24
Once you start firing coal, residual oil, or solid oil-derived fuel, you must vent
emissions to the main stack(s). You must comply with the applicable emission
limits within 4 hours of start of electricity generation. You must engage and
operate your particulate matter control(s) within 1 hour of first firing of coal,
residual oil, or solid oil-derived fuel.
You must start all other applicable control devices as expeditiously as possible,
considering safety and manufacturer/supplier recommendations, but, in any case,
when necessary to comply with other standards made applicable to the EGU by a
permit limit or a rule other than this Subpart that require operation of the control
devices.
Relative to the syngas not fired in the combustion turbine of an IGCC EGU during
startup, you must either: (1) flare the syngas, or (2) route the syngas to duct
burners, which may need to be installed, and route the flue gas from the duct
burners to the heat recovery steam generator.
If you choose to use just one set of sorbent traps to demonstrate compliance with
Hg emission limits, you must comply with all applicable Hg emission limits at all
times; otherwise, you must comply with all applicable emission limits at all times
except for startup or shutdown periods conforming to this practice. You must
collect monitoring data during startup periods, as specified in 40 CFR §
63.10020(a) and (e). You must keep records during startup periods, as provided in
40 CFR §§ 63.10032 and 63.10021(h). Any fraction of an hour in which startup
occurs constitutes a full hour of startup. You must provide reports concerning
activities and startup periods, as specified in 40 CFR §§ 63.10011(g), 63.10021(i),
and 63.10031.
4. A coal-fired, liquid You must operate all CMS during shutdown. You must also collect appropriate
oil-fired, or solid oil- data, and you must calculate the pollutant emission rate for each hour of
derived fuel-fired EGU shutdown.
during shutdown
While firing coal, residual oil, or solid oil-derived fuel during shutdown, you must
vent emissions to the main stack(s) and operate all applicable control devices and
continue to operate those control devices after the cessation of coal, residual oil,
or solid oil-derived fuel being fed into the EGU and for as long as possible
thereafter considering operational and safety concerns. In any case, you must
operate your controls when necessary to comply with other standards made
applicable to the EGU by a permit limit or a rule other than this Subpart and that
require operation of the control devices.
If, in addition to the fuel used prior to initiation of shutdown, another fuel must be
used to support the shutdown process, that additional fuel must be one or a
combination of the clean fuels defined in 40 CFR § 63.10042 and must be used to
the maximum extent possible.
Relative to the syngas not fired in the combustion turbine of an IGCC EGU during
shutdown, you must either: (1) flare the syngas, or (2) route the syngas to duct
burners, which may need to be installed, and route the flue gas from the duct
burners to the heat recovery steam generator.
You must comply with all applicable emission limits at all times except during
startup periods and shutdown periods at which time you must meet this work
practice. You must collect monitoring data during shutdown periods, as specified
in 40 CFR § 63.10020(a). You must keep records during shutdown periods, as
Attachment C - Page 21 of 24
provided in 40 CFR §§ 63.10032 and 63.10021(h). Any fraction of an hour in
which shutdown occurs constitutes a full hour of shutdown. You must provide
reports concerning activities and shutdown periods, as specified in 40 CFR §§
63.10011(g), 63.10021(i), and 63.10031.
Table 5 to Subpart UUUUU of Part 63—Performance Testing Requirements
As stated in 40 CFR § 63.10007, you must comply with the following requirements for performance
testing for existing, new or reconstructed affected sources:1
To conduct a
performance test for
the following
pollutant . . .
Using . .
1. Filterable
Particulate matter
(PM)
You must perform the
following activities, as
applicable to your input- or
output-based emission
. limit . . .
PM CEMS a. Install, certify, operate, and
maintain the PM CEMS
Using2 . . .
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 Part 75 of this chapter and §40 CFR §
the diluent gas, flow rate,
63.10010(a), (b), (c), and (d).
and/or moisture monitoring
systems
c. Convert hourly emissions
concentrations to 30 boiler
operating day rolling average
lb/MMBtu or lb/MWh emissions
rates
3Incorporated
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)).
by reference, see 40 CFR § 63.14.
Table 7 to Subpart UUUUU of Part 63—Demonstrating Continuous Compliance
As stated in 40 CFR § 63.10021, you must show continuous compliance with the emission
limitations for affected sources according to the following:
Attachment C - Page 22 of 24
If you use one of the following to meet
applicable emissions limits, operating limits,
or work practice standards . . .
You demonstrate continuous compliance by . . .
1. CEMS to measure filterable PM, SO2, HCl, HF, Calculating the 30- (or 90-) boiler operating day rolling
or Hg emissions, or using a sorbent trap
arithmetic average emissions rate in units of the
monitoring system to measure Hg
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,
Calculating the results of the testing in units of the
solid oil derived fired, or liquid oil-fired EGUs to applicable emissions standard.
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
5. Conducting periodic performance tune-ups of Conducting periodic performance tune-ups of your
your EGU(s)
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.
a. Information required in 40 CFR § 63.10031(c)(1) through (4); and
Compliance b. If there are no deviations from any emission limitation (emission
report
limit and operating limit) that applies to you and there are no
deviations from the requirements for work practice standards in
Table 3 to Subpart UUUUU that apply to you, a statement that there
were no deviations from the emission limitations and work practice
standards during the reporting period. If there were no periods
during which the CMSs, including continuous emissions monitoring
system, and operating parameter monitoring systems, were out-ofcontrol as specified in 40 CFR § 63.8(c)(7), a statement that there
were no periods during which the CMSs were out-of-control during
the reporting period; and
Semiannually
according to the
requirements in 40
CFR § 63.10031(b).
c. If you have a deviation from any emission limitation (emission limit
and operating limit) or work practice standard during the reporting
period, the report must contain the information in 40 CFR §
63.10031(d). If there were periods during which the CMSs, including
continuous emissions monitoring systems and continuous
parameter monitoring systems, were out-of-control, as specified in
Attachment C - Page 23 of 24
40 CFR § 63.8(c)(7), the report must contain the information in 40
CFR § 63.10031(e)
Attachment C - Page 24 of 24