**TECHNICAL SUPPORT DOCUMENT**

TECHNICAL INFORMATION PRESENTED IN REVIEW OF AN

APPLICATION FOR A PART 70 OPERATING PERMIT

SUBMITTED BY

####### Nevada Power Company

for

**Silverhawk Electric Generating Station**

**North Las Vegas, Nevada**

**Part 70 Operating Permit Number: 1584**

SIC Code - 4911: Electric Utility Services

NAICS Code -- 221112: Fossil Fuel Electric Power Generation

![](media/image1.wmf){width="1.3229166666666667in"
height="1.2958333333333334in"}

Clark County

Department of Air Quality and Environmental Management

Permitting Section

May 2006

***This Technical Support Document (TSD) accompanies the proposed Part
70 Operating Permit for Nevada Power Company.***

**[TABLE OF CONTENTS]{.underline}**

> Page

[I. EXECUTIVE SUMMARY 3](#i.-executive-summary)

[II. FACILITY INFORMATION 4](#ii.-facility-information)

[A. General 4](#a.-general)

[B. Description of Process 4](#b.-description-of-process)

[C. Permitting History 5](#c.-permitting-history)

[D. Operating Scenario 5](#d.-operating-scenario)

[E. Proposed Exemptions 5](#e.-proposed-exemptions)

[III. EMISSIONS INFORMATION 5](#iii.-emissions-information)

[A. Total Facility Potential to Emit
5](#a.-total-facility-potential-to-emit)

[B. Emission Units and PTE 6](#b.-emission-units-and-pte)

[C. Performance Testing and Continuous Emission Monitoring
8](#c.-performance-testing-and-continuous-emission-monitoring)

[IV. REGULATORY REVIEW 10](#iv.-regulatory-review)

[A. Local Regulatory Requirements 10](#a.-local-regulatory-requirements)

[B. Federally Applicable Regulations
13](#b.-federally-applicable-regulations)

[V. COMPLIANCE 31](#__RefHeading___Toc98123059)

[A. Compliance Certification 31](#a.-compliance-certification)

[B. Summary of Monitoring for Compliance
32](#b.-summary-of-monitoring-for-compliance)

[VI. EMISSION REDUCTION CREDITS (OFFSETS)
33](#vi.-emission-reduction-credits-offsets)

[VII. ADMINISTRATIVE REQUIREMENTS 33](#vii.-administrative-requirements)

# I. EXECUTIVE SUMMARY

The Silverhawk Electric Generating Station, owned by Nevada Power
Company, is located in\
Apex, Nevada in the hydrographic area 216 (Apex Valley)

The facility consists of two 175 megawatt natural-gas turbines, each
equipped with a 530 MMBtu-per-hour natural-gas duct burner, a 250
horsepower diesel emergency fire pump, a 100 horsepower liquefied
petroleum gas (LPG)-fired emergency generator, and a 6,600
gallon-per-minute cooling tower. The potential emissions for the
facility are shown in the table below.

Table 1-1: Maximum Facility PTE (tons per year)

+---------+---------+---------+---------+---------+---------+--------+
| **P     | **      | **CO**  | **      | **VOC** | ####    | #      |
| M~10~** | NO~X~** |         | SO~2~** |         | ### HAP | ###### |
|         |         |         |         |         |         |  NH~3~ |
+---------+---------+---------+---------+---------+---------+--------+
| **1     | **3     | **5     | **      | **      | *       | **23   |
| 48.91** | 09.58** | 61.05** | 10.31** | 85.31** | *6.18** | 6.00** |
+---------+---------+---------+---------+---------+---------+--------+

Clark County Department of Air Quality and Environmental Management
(DAQEM) has delegated authority to implement the requirements of the
Part 70 operating permit program.

Based on information submitted by the applicant and a technical review
performed by the DAQEM staff, the DAQEM proposes the issuance of a Part
70 Operating Permit to Nevada Power Company.

# II. FACILITY INFORMATION

## A. General

+------------------------------+---------------------------------------+
| Permittee                    | ######### Nevada Power Company        |
|                              | {#nevada-power-company-1 .unnumbered} |
+------------------------------+---------------------------------------+
|                              |                                       |
+------------------------------+---------------------------------------+
| Mailing Address              | P.O. Box 337260                       |
|                              |                                       |
|                              | North Las Vegas, Nevada 89033         |
+------------------------------+---------------------------------------+
|                              |                                       |
+------------------------------+---------------------------------------+
| Contacts                     | William M. Simko, Plant Manager       |
+------------------------------+---------------------------------------+
|                              |                                       |
+------------------------------+---------------------------------------+
| Phone Number                 | \(702\) 207-7002                      |
+------------------------------+---------------------------------------+
| Fax Number                   | \(702\) 207-7027                      |
+------------------------------+---------------------------------------+
|                              |                                       |
+------------------------------+---------------------------------------+
| Source Location              | 15111 Apex Power Parkway              |
|                              |                                       |
|                              | North Las Vegas, Nevada 89124         |
+------------------------------+---------------------------------------+
|                              |                                       |
+------------------------------+---------------------------------------+
| Hydrographic Area            | 216                                   |
+------------------------------+---------------------------------------+
|                              |                                       |
+------------------------------+---------------------------------------+
| Township, Range, Section     | T18S, R63E, Section 5                 |
+------------------------------+---------------------------------------+
|                              |                                       |
+------------------------------+---------------------------------------+
| SIC Code                     | 4911 - Electric Services              |
+------------------------------+---------------------------------------+
| NAICS Code                   | 221112 -- Fossil Fuel Electric Power  |
|                              | Generation                            |
+------------------------------+---------------------------------------+

## B. Description of Process

The Silverhawk Electric Generating (Nevada Power Company) facility is
located in the Apex Industrial Park in North Las Vegas, Nevada,
approximately 20 miles northeast of Las Vegas. The facility is located
in the Apex Hidden Valley Valley airshed, hydrographic area 216. This
area is designated nonattainment for ozone (e.g. NO~X~ and VOC) and
prevention of significant deterioration (PSD) for PM~10~, CO, and SO~2~.

The facility consists of two Westinghouse 501 FD natural gas-fired
combined-cycle combustion turbine/generators, each equipped with dry
low-NO~X~ burners and a heat recovery steam generator (HSRG) unit with a
530 MMBtu-per-hour natural gas-fired duct burner for supplemental
firing. The two HSRGs feed steam to a single steam turbine. The
combined-cycle units each produce approximately 175 MW of electricity.
The total plant net dependable rating with duct burners and the steam
turbine in service is 570 MW.

Also present at the facility are one 100 horsepower liquefied petroleum
gas (LPG)-fired emergency generator, one 250 horsepower diesel emergency
fire pump and a 6,600 gallon-per-minute cooling tower.

[]{.mark}

## C. Permitting History

####### 

#### Table II-C-1: Permits Issued to Nevada Power Company 

+---------+------------+-----------------------------------------------+
| **Date  | **Permit** | **Description**                               |
| I       |            |                                               |
| ssued** | **Number** |                                               |
+=========+============+===============================================+
| 12/     | Mo         | Issuance of amended operating permit          |
| 12/2005 | dification |                                               |
|         | 0          |                                               |
+---------+------------+-----------------------------------------------+
| 05/     | Mo         | Issuance of initial operating permit          |
| 14/2004 | dification |                                               |
|         | 0          |                                               |
+---------+------------+-----------------------------------------------+
| 08/     | Mo         | Issuance of initial authority to construct    |
| 14/2002 | dification |                                               |
|         | 0          |                                               |
+---------+------------+-----------------------------------------------+

### Table II-C-2: BACT Determinations for Nevada Power Company

+-------+------------------------------------+------------------------+
| ##    | **Description**                    | **BACT Technology**    |
| ##### |                                    |                        |
|  E.U. |                                    |                        |
+-------+------------------------------------+------------------------+
| A0    | 175 MW Natural Gas Turbine with a  | SCR, dry low-NO~X~     |
| 1/A02 | 530 MMBtu/hr HSRG                  | burners, oxidation     |
|       |                                    | catalyst, natural gas  |
|       |                                    | combustion, inlet air  |
|       |                                    | filters                |
+-------+------------------------------------+------------------------+
| A0    | 175 MW Natural Gas Turbine with a  | SCR, dry low-NO~X~     |
| 3/A04 | 530 MMBtu/hr HSRG                  | burners, oxidation     |
|       |                                    | catalyst, natural gas  |
|       |                                    | combustion, inlet air  |
|       |                                    | filters                |
+-------+------------------------------------+------------------------+
| A05   | 250 hp Diesel Emergency Fire Pump  | Timing retard,         |
|       |                                    | turbocharging,         |
|       |                                    | aftercooling, low      |
|       |                                    | sulfur diesel          |
+-------+------------------------------------+------------------------+
| A06   | 100 hp LPG Emergency Generator     | Timing retard,         |
|       |                                    | turbocharging,         |
|       |                                    | aftercooling           |
+-------+------------------------------------+------------------------+
| A07   | 6,600 gpm Cooling Tower            | 8,144 ppm TDS, 6,600   |
|       |                                    | gpm, 0.001 percent     |
|       |                                    | drift loss             |
+-------+------------------------------------+------------------------+

## D. Operating Scenario

The combustion turbines are both fired on natural gas and are allowed to
operate 8,760 hours per year. The associated natural gas-fired duct
burners are allowed to operate 24 hours per day and up to 2,000 hours
equivalent full load per rolling 12-month period. The diesel emergency
fire pump and the LPG emergency generator may each be tested up to 250
hours per rolling 12-month period. The cooling tower may operate up to
8,760 hours per year.

## 

## E. Proposed Exemptions

There are no restrictions for the operation of the diesel emergency fire
pump and the LPG emergency generator during emergency situations.

# III. EMISSIONS INFORMATION

## A. Total Facility Potential to Emit

The facility potential to emit (PTE) for pollutants (Table III-A-1)
reflects the permitted emission limits established in the January 27,
2006 ATC/OP (Permit 1584, Modification 0, Amendment 1).

#### Table III-A-1: Maximum Facility Potential to Emit (tons per year)

+---------+---------+---------+---------+---------+---------+--------+
| **P     | **      | **CO**  | **      | **VOC** | ####    | #      |
| M~10~** | NO~X~** |         | SO~2~** |         | ### HAP | ###### |
|         |         |         |         |         |         |  NH~3~ |
+---------+---------+---------+---------+---------+---------+--------+
| **1     | **3     | **5     | **      | **      | *       | **23   |
| 48.91** | 09.58** | 61.05** | 10.31** | 85.31** | *6.18** | 6.00** |
+---------+---------+---------+---------+---------+---------+--------+

## 

## B. Emission Units and PTE

The following tables summarize the allowable limits for each emission
unit.

**Table III-B-1: Emission Units at Facility**

  ----------------------------------------------------------------------------
  **E.U.**   **Description**                                       **SCC \#**
  ---------- ----------------------------------------------------- -----------
  A01        Westinghouse 501FD 175 MW natural gas only turbine;   20100201
             1,744 MMBtu/hr LHV; 1,980 MMBtu/hr HHV                

  A02        530 MMBtu/hr (HHV) duct-burner HRSG associated with   10100601
             A01                                                   

  A03        Westinghouse 501FD 175 MW natural gas only turbine    20100201
             1,744 MMBtu/hr LHV; 1,980 MMBtu/hr HHV                

  A04        530 MMBtu/hr (HHV) duct-burner HRSG associated with   10100601
             A03                                                   

  A05        Diesel fire pump, 250 bhp                             20200102

  A06        Emergency LPG generator, 100 bhp                      20200102

  A07        International Cooling Tower, 6,600 gpm                38500101
  ----------------------------------------------------------------------------

**^Table\ III-B-2:\ Facility\ Potential\ to\ Emit\ (pounds\ per\ hour)^**1

  ------------ ------------ ----------- ----------- ----------- ----------- -----------
  **E.U.**     **PM~10~**   **NO~X~**   **CO**      **SO~2~**   **VOC**     **NH~3~**

  A01/A02      19.80        23.00       22.40       1.50        6.40        34.00

  A03/A04      19.80        23.00       22.40       1.50        6.40        34.00

  A05          0.60         7.80        1.70        0.50        0.60        0.00

  A06          0.01         3.06        0.42        0.01        0.09        0.00

  A07          0.27         0.00        0.00        0.00        0.00        0.00

  **Total      **40.48**    **56.86**   **46.92**   **3.51**    **13.49**   **68.00**
  PTE**                                                                     
  ------------ ------------ ----------- ----------- ----------- ----------- -----------

^1^Hourly emission limits for each turbine/duct burner pair are based on
worst-case scenario of 100 percent load at

104 ^0^F with duct burning, except SO~2~. For SO~2~ emissions,
worst-case scenario is 100 percent load at 9 ^0^F.

**^Table\ III-B-3:\ Facility\ Potential\ to\ Emit\ (tons\ per\ year)^**1

  ----------------------------------------------------------------------------------------
  **E.U.**     **PM~10~**   **NO~X~**    **CO**       **SO~2~**   **VOC**     **NH~3~**
  ------------ ------------ ------------ ------------ ----------- ----------- ------------
  A01/A02      73.80        154.10       280.40       5.10        42.60       118.00

  A03/A04      73.80        154.10       280.40       5.10        42.60       118.00

  A05          0.10         1.00         0.20         0.10        0.10        0.00

  A06          0.01         0.38         0.05         0.01        0.01        0.00

  A07          1.20         0.00         0.00         0.00        0.00        0.00

  **Total      **148.91**   **309.58**   **561.05**   **10.31**   **85.31**   **236.00**
  PTE**                                                                       
  ----------------------------------------------------------------------------------------

> ^1^ Annual emissions for turbine/duct burner pairs (A01/A02) and
> (A03/A04) are based on normal operations of 6,000 hours of turbines
> without duct firing at 100 percent load and 66 ^O^F, 2,000 hours of
> turbines operating with duct firing at 100 percent load and 104 ^O^F,
> and 900 hours in start-up/shut-down cycles. (See Table III-B-4.)
>
> []{.mark}
>
> []{.mark}
>
> []{.mark}
>
> []{.mark}
>
> Table III-B-4: Emission Estimates per Turbine Based upon 900 Annual
> Hours of Start-up/Shut-down Cycling

+----------+---------+-----------+------------+----------+----------+
| *        | **P     | **NO~x~** | **CO**     | *        | **VOCs** |
| *Event** | M~10~** |           |            | *SO~2~** |          |
+----------+---------+-----------+------------+----------+----------+
|          | lbs     | lbs/even  | lbs/eve    | l        | l        |
|          | /event/ | t/turbine | nt/turbine | bs/event | bs/event |
|          | turbine |           |            | /turbine | /turbine |
+----------+---------+-----------+------------+----------+----------+
| **Cold   | 54.00   | 585.00    | 2,706.00   | 3.30     | 137.00   |
| start:   |         |           |            |          |          |
| 45       |         |           |            |          |          |
| events   |         |           |            |          |          |
| per year |         |           |            |          |          |
| @ 3      |         |           |            |          |          |
| hours    |         |           |            |          |          |
| each**   |         |           |            |          |          |
+----------+---------+-----------+------------+----------+----------+
| **       | 36.00   | 325.00    | 1000.00    | 2.20     | 91.40    |
| Warm/hot |         |           |            |          |          |
| starts:  |         |           |            |          |          |
| 240      |         |           |            |          |          |
| events   |         |           |            |          |          |
| per year |         |           |            |          |          |
| @ 2      |         |           |            |          |          |
| hours    |         |           |            |          |          |
| each**   |         |           |            |          |          |
+----------+---------+-----------+------------+----------+----------+
| **S      | 18.00   | 163.00    | 160.00     | 1.10     | 45.70    |
| hutdown: |         |           |            |          |          |
| 285**    |         |           |            |          |          |
|          |         |           |            |          |          |
| **events |         |           |            |          |          |
| per year |         |           |            |          |          |
| @ 1 hour |         |           |            |          |          |
| each**   |         |           |            |          |          |
+----------+---------+-----------+------------+----------+----------+

> Table III-B-5: Federally Enforceable Concentration Limits for Each
> Turbine and Duct Burner- Normal Operations 3-hour Average

  --------- ---------- ------------- -------------- -------------- ------------
            **NO~x~ @  **CO @ 15%    **NH~3~ @ 15%  **VOC @ 15%    **PM~10~**
            15% O~2~** O~2~**        O~2~**         O~2~**         

  With Duct 2.5 ppmvd  4 ppmvd       10 ppmvd       2.0 ppmvd      19.80 lb/hr
  Firing                                                           

  Without   2.5 ppmvd  4 ppmvd       10 ppmvd       2.0 ppmvd      16.50 lb/hr
  Duct                                                             
  Firing                                                           
  --------- ---------- ------------- -------------- -------------- ------------

**Table III-B-6: Federally Enforceable Hazardous Air Pollutant Emissions
(HAPs), Tons per Year for Facility^1^**

  ---------------------------------- ------------------------------------
  **HAP**                            **Maximum Potential Emissions**

  Acetaldehyde                       0.17

  Acrolein                           0.10

  Benzene                            0.19

  1,3-Butadiene                      0.01

  Dichlorobenzene                    0.02

  Ethylbenzene                       0.51

  Formaldehyde                       0.80

  Hexane                             1.86

  Naphthalene                        0.02

  PAHs                               0.03

  Toluene                            1.23

  Xylene                             1.01

  Manganese                          0.01

  Molybdenum                         0.02

  Nickel                             0.03

  Selenium                           0.17

  **Total**                          **6.18**
  ---------------------------------- ------------------------------------

^1^Facility Hazardous Air Pollutant (HAP) emissions are calculated based
on emission factors from the California Air Toxics Emission Factors
(CATEF) Database Version 1.2, EPA's AP-42 Compilation of Air Pollutant
Emission Factors, Section 3.1, April 2000, and the fuel burning
limitations assigned to each emission unit in this ATC/OP.

Only those HAPs with a potential to exceed 0.0005 tons per year (1.0
pounds per year) are listed. These factors are being used by DAQEM to
more accurately determine HAP emissions and possible source subjectivity
to MACT standards per the April 2001 promulgated rule. No single turbine
HAP emission shall exceed ten tons per year and total single turbine HAP
emissions shall not exceed 25 tons per year. Therefore, this facility is
not subject to 40 CFR 63 Subpart YYYY for combustion turbines.

## 

## C. Performance Testing and Continuous Emission Monitoring

Initial performance testing for the turbines was completed on May 4,
2004. Any additional required testing will be performed using the
following methods:

Table III-C-1: Performance Testing Requirements (40 CFR 60, Appendix A)

  ------------------------------ --------------- -------------------------------
  **Test Point**                 **Pollutant**   **Method**

  Turbine/HRSG Exhaust Stack     NO~X~           Chemiluminescence Analyzer (EPA
                                                 Method 7E, Method 20)

  Turbine/HRSG Exhaust Stack     CO              EPA Method 10

  Turbine/HRSG Exhaust Stack     VOC             EPA Method 25A

  Turbine/HRSG Exhaust Stack     NH~3~ slip      Method preapproved by DAQEM/EPA

  Turbine/HRSG Exhaust Stack     PM~10~          EPA Method 201/202 or 201A/202

  Turbine/HRSG Exhaust Stack     Opacity         EPA Method 9

  Stack Gas Parameters           \-\--           EPA Method 1, Method 2, Method
                                                 3, Method 4
  ------------------------------ --------------- -------------------------------

[]{.mark}

Annual RATA testing must be performed on each NO~X~, CO, and O~2~
Continuous Emissions Monitoring Systems (CEMS).

[]{.mark}

All performance tests on the turbine units must conform to 40 CFR 60
Subparts A and GG, and 40 CFR 75. All performance tests on the auxiliary
boiler must conform to AQR Section 49 \[Amended 12/20/05\]:

The Owner and/or Operator shall conduct the required initial performance
test within 60 days after achieving the maximum production rate at which
the affected Boiler will be operated, but not later than 180 days after
initial startup of such Boiler with a maximum heat input rating equal to
or greater than 4 MMBtu/hr and shall comply with the following
provisions:

> 49.5.1.1 Conduct an initial performance test in accordance with the
> EPA Test Methods listed in Table 49.5-1 to demonstrate compliance with
> the standards of Subsection 49.4 and/or applicable permit
> requirements;
>
> 49.5.1.2 Comply with the [emission]{.smallcaps} standards of
> Subsection 49.4 or the applicable standard(s) of Sections 13, 14, or
> 20, and any applicable NSPS or NESHAP, whichever is more restrictive;
>
> 49.5.1.3 Conduct periodic performance testing, at least once during
> every 5-year period beginning from the date of initial performance
> testing and at 5-year intervals thereafter, on each gas-fired Boiler
> with a maximum heat input rating equal to or greater than 10 MMBtu/hr
> to demonstrate compliance with the [emission]{.smallcaps} standard of
> Subsection 49.4 and/or comply with the requirements contained in
> Subsection 49.6, as appropriate, during periods when Boilers are not
> performance tested.
>
> 49.5.1.4 Shall submit a performance test protocol in accordance with
> Section 14.
>
> 49.5.1.5 Shall furnish the Compliance Supervisor with a written report
> containing the results of the performance test within 60 days after
> conducting such test; and
>
> 49.5.1.6 May use an Alternative Testing Procedure provided the
> procedure has the prior written approval of the [Control
> Officer]{.smallcaps} and the procedure demonstrates compliance with
> the standard(s) of Subsection 49.4.

#### 

#### Continuous Emissions Monitoring

Nevada Power Company is operating a NO~X~ and CO CEMS on both turbine
units. The January 27, 2006 ATC/OP contains the following requirements:

CEMS installed on emission units A01 and A03 shall demonstrate
continued, direct compliance with operational limitations, and the
three-hour rolling average and annual emissions limitations for CO and
NO~X~ specified in Section III of this document. The CEMS shall monitor
and record the following parameters for each individual CTG:

1.  exhaust gas concentration of NO~X~, CO, and diluent O~2~, including
    periods of startup and shutdown;

2.  exhaust gas flow rate (by direct or indirect methods);

3.  fuel flow rate;

4.  hours of operation;

5.  three-hour rolling averages for NO~X~ concentration and CO
    concentration;

6.  hourly, daily, and quarterly accumulated mass emissions of NO~X~ and
    CO; and

7.  hours of downtime for each CEMS.

Excluding start-up or shut-down periods not to exceed 180 minutes per
unit per event, any exceedance of the hourly, daily, or annual CO and/or
NO~X~ emissions limitations expressed in Section III as determined by
the CEMS shall be considered a violation of the emission limit imposed
and may result in enforcement action.

Nevada Power Company must also operate an ammonia predictive emissions
monitoring system (PEMS) on both combined cycle emission unit's stack.
The ammonia PEMS is based on the principle that NO~x~ reduction occurs
at a 1:1 molar ratio with ammonia. Typically though, more ammonia is
injected than is stoichiometrically needed because the physical process
does not allow for ideal conditions like complete mixing, uniform
ammonia flow, gas flow, temperature distributions, etc. The unreacted
ammonia slips through the catalyst bed and out of the stack as ammonia
emissions.

The PEMS uses two NO~x~ readings: an ammonia flow reading and several
constants to calculate an estimate of ammonia emissions. One NO~x~
reading is from an analyzer at the selective catalytic reduction (SCR)
inlet, and the other is from the stack CEMS analyzer. These measure the
change in NO~x~ across the SCR (always a reduction), which is converted
to an ideal ammonia usage based on the stoichiometric principle noted
above. This is then subtracted, on a molar basis, from actual ammonia
usage and converted to an ammonia concentration going out of the stack.

The calculation is carried out in the CEMS and stored in the computer
that stores the CEMS parameters.

# 

# IV. REGULATORY REVIEW

## A. Local Regulatory Requirements

The DAQEM has determined that the following public law, statutes and
associated regulations are applicable:

1.  Clean Air Act, as amended (CAAA), Authority: 42 U.S.C. § 7401, et
    seq.;

2.  Title 40 of the Code of Federal Regulations (CFR);

3.  Nevada Revised Statutes (NRS), Chapter 445B;

4.  Portions of the AQR that are included in the State Implementation
    Plan (SIP) for Clark County, Nevada. SIP requirements are federally
    enforceable. All requirements from Authority to Construct permits
    and Section 16 Operating Permits issued by DAQEM are federally
    enforceable because these permits were issued pursuant to
    SIP-included sections of the AQR; and

5.  Portions of the AQR that are [not]{.underline} included in the SIP.
    These locally applicable requirements are locally enforceable only.

The Nevada Revised Statutes (NRS) and the Clean Air Act Amendments
(CAAA) are public laws that establish the general authority for the
Regulations mentioned.

The DAQEM Part 70 (Title V) Program received Final Approval on November
30, 2001 with publication of that approval appearing in the Federal
Register December 5, 2001 Vol. 66, No. 234. AQR Section 19 - Part 70
Operating Permits \[Amended 07/01/04\] details the Clark County Part 70
Operating Permit Program. These regulations may be accessed on the
Internet at: [http://www.co.clark.nv. us/air_quality/Regs.htm]()

Local regulations contain sections that are federally enforceable and
sections that are locally enforceable only. Locally enforceable only
rules have not been approved by EPA for inclusion into the State
Implementation Plan (SIP). Requirements and conditions that appear in
the Part 70 OP which are related only to non-SIP rules are notated as
locally enforceable only.

Table IV-A-1: AQR Sections 12 and 55 Summary Table for This Facility

+----------+------+---------+------+------+---------+--------+------+
|          | **   | **      | **   | *    | **VOC** | *      | *    |
|          | PM~1 | NO~X~** | CO** | *SO~ |         | *HAP** | *TCS |
|          | 0~** |         |      | 2~** |         |        | (    |
|          |      |         |      |      |         |        | NH~3 |
|          |      |         |      |      |         |        | ~)** |
+----------+------+---------+------+------+---------+--------+------+
| ######   | PSD  | Basic   | PSD  | PSD  | Basic   | N/A    | N/A  |
| Air Qual |      | nonatt  |      |      | nonatt  |        |      |
| ity Area |      | ainment |      |      | ainment |        |      |
|          |      | (ozone) |      |      | (ozone) |        |      |
+----------+------+---------+------+------+---------+--------+------+
| **       | **   | **3     | **   | *    | **      | **     | **   |
| Facility | 148. | 09.58** | 561. | *10. | 85.31** | 6.18** | 236. |
| PTE      | 91** |         | 05** | 31** |         |        | 00** |
| (tpy)**  |      |         |      |      |         |        |      |
+----------+------+---------+------+------+---------+--------+------+
| **Major  | ≥    | ≥ 100   | ≥    | ≥    | ≥ 100   | ≥ 10   | ≥ 1  |
| Source** | 100  | tpy     | 100  | 100  | tpy     | tpy    | tpy  |
|          | tpy  |         | tpy  | tpy  |         | for    |      |
|          |      |         |      |      |         | each   |      |
|          |      |         |      |      |         | HAP,   |      |
|          |      |         |      |      |         | or ≥   |      |
|          |      |         |      |      |         | 25 tpy |      |
|          |      |         |      |      |         | for    |      |
|          |      |         |      |      |         | co     |      |
|          |      |         |      |      |         | mbined |      |
|          |      |         |      |      |         | HAPs   |      |
+----------+------+---------+------+------+---------+--------+------+

**Discussion:** Nevada Power Company is a major source of PM~10~, NO~X,~
CO, and TCS (NH~3~). As part of the original New Source Review Analysis
all of these emissions triggered notice of proposed action.

Table IV-A-2: Clark County Department of Air Quality and Environmental
Management -- Air Quality and State Implementation Plan with Facility
Compliance or Requirement

+-------------------+------------------------------+----+-------------+
| Applicable        | **Applicable Subsection -    | *  | *           |
| Section -- Title  | Title**                      | *S | *Affected** |
|                   |                              | IP |             |
|                   |                              | ** | **Emission  |
|                   |                              |    | Unit**      |
+===================+==============================+====+=============+
| 0\. Definitions   | applicable definitions       | y  | entire      |
|                   |                              | es | facility    |
+-------------------+------------------------------+----+-------------+
| 1\. Definitions   | applicable definitions --    | y  | entire      |
|                   |                              | es | facility    |
|                   | > "Affected Facility", "Air  |    |             |
|                   | > Contaminant", "Air         |    |             |
|                   | > Pollution Control          |    |             |
|                   | > Committee", "Area Source", |    |             |
|                   | > "Atmosphere", "Board",     |    |             |
|                   | > "Commercial Off-Road       |    |             |
|                   | > Vehicle Racing", "Dust",   |    |             |
|                   | > "Existing Facility",       |    |             |
|                   | > "Existing Gasoline         |    |             |
|                   | > Station", "Fixed Capital   |    |             |
|                   | > Cost", "Fumes", "Health    |    |             |
|                   | > District", "Hearing        |    |             |
|                   | > Board", "Integrated        |    |             |
|                   | > Sampling", "Minor Source", |    |             |
|                   | > "Mist", "New Gasoline      |    |             |
|                   | > Station", "New Source",    |    |             |
|                   | > "NIC", "Point Source",     |    |             |
|                   | > "Shutdown", "Significant", |    |             |
|                   | > "Single Source", "Smoke",  |    |             |
|                   | > "Source of Air             |    |             |
|                   | > Contaminant", "Special     |    |             |
|                   | > Mobile Equipment",         |    |             |
|                   | > "Standard Commercial       |    |             |
|                   | > Equipment", "Standard      |    |             |
|                   | > Conditions", "Start Up",   |    |             |
|                   | > "Stop Order", "Uncombined  |    |             |
|                   | > Water", and "Vapor         |    |             |
|                   | > Disposal System"           |    |             |
+-------------------+------------------------------+----+-------------+
| 4\. Control       | all subsections              | y  | entire      |
| Officer           |                              | es | facility    |
+-------------------+------------------------------+----+-------------+
| 5\. Interference  | all subsections              | y  | entire      |
| with Control      |                              | es | facility    |
| Officer           |                              |    |             |
+-------------------+------------------------------+----+-------------+
| 8\. Persons       | all subsections              | y  | entire      |
| Liable for        |                              | es | facility    |
| Penalties -       |                              |    |             |
| Punishment:       |                              |    |             |
| Defense           |                              |    |             |
+-------------------+------------------------------+----+-------------+
| 9\. Civil         | all subsections              | y  | entire      |
| Penalties         |                              | es | facility    |
+-------------------+------------------------------+----+-------------+
| 10\. Compliance   | when applicable; applicable  | y  | entire      |
| Schedule          | subsections                  | es | facility    |
+-------------------+------------------------------+----+-------------+
| 11\. Ambient Air  | applicable subsections       | y  | entire      |
| Quality Standards |                              | es | facility    |
+-------------------+------------------------------+----+-------------+
| 12\.              | All subsections              | y  | entire      |
| Preconstruction   | [except]{.underline} the     | es | facility    |
| Review for New or | following:                   |    |             |
| Modified          |                              |    |             |
| Stationary        | § 12.2.18 HAP Sources in     |    |             |
| Sources           | Clark County.                |    |             |
|                   |                              |    |             |
|                   | § 12.2.20 Additional         |    |             |
|                   | Requirements for [Stationary |    |             |
|                   | Source]{.smallcaps}s with    |    |             |
|                   | Beryllium, Mercury, Vinyl    |    |             |
|                   | Chloride, or Asbestos        |    |             |
|                   | [Emissions]{.smallcaps} in   |    |             |
|                   | Clark County                 |    |             |
+-------------------+------------------------------+----+-------------+
| 14\. New Source   | CCAQR Section 14.1.56:       | no | Applicable  |
| Performance       | Subparts Da and GG Standards |    | -- CTG      |
| Standards         | of Performance for Gas       |    | units       |
|                   | Turbines                     |    |             |
+-------------------+------------------------------+----+-------------+
| 16\. Operating    | all subsections              | y  | entire      |
| Permits           |                              | es | facility    |
+-------------------+------------------------------+----+-------------+
| 18\. Permit and   | § 18.1 Operating Permit Fees | y  | entire      |
| Technical Service |                              | es | facility    |
| Fees              | § 18.2 Annual Emission Unit  |    |             |
|                   | Fees                         |    |             |
|                   |                              |    |             |
|                   | § 18.4 New Source Review     |    |             |
|                   | Application Review Fee       |    |             |
|                   |                              |    |             |
|                   | § 18.5 Part 70 Application   |    |             |
|                   | Review Fee                   |    |             |
|                   |                              |    |             |
|                   | § 18.6 Annual Part 70        |    |             |
|                   | Emission Fee                 |    |             |
|                   |                              |    |             |
|                   | § 18.14 Billing Procedures   |    |             |
+-------------------+------------------------------+----+-------------+
| 19\. Part 70      | § 19.2 Applicability         | N  | entire      |
| Operating Permit  |                              | /A | facility    |
|                   | § 19.3 Part 70 Permit        |    |             |
| Federal Approval  | Applications                 |    |             |
| (11/25/01)        |                              |    |             |
|                   | § 19.4 Part 70 Permit        |    |             |
|                   | Content                      |    |             |
|                   |                              |    |             |
|                   | § 19.5 Permit Issuance,      |    |             |
|                   | Renewal, Re-openings, and    |    |             |
|                   | Revisions                    |    |             |
|                   |                              |    |             |
|                   | § 19.6 Permit Renewal by the |    |             |
|                   | EPA and Affected States      |    |             |
|                   |                              |    |             |
|                   | § 19.7 Fee Determination and |    |             |
|                   | Certification                |    |             |
+-------------------+------------------------------+----+-------------+
| 24\. Sampling and | § 24.1 Requirements for      | y  | entire      |
| Testing - Records | installation and maintenance | es | facility    |
| and Reports       | of sampling and testing      |    |             |
|                   | facilities                   |    |             |
|                   |                              |    |             |
|                   | § 24.2 Requirements for      |    |             |
|                   | emissions record keeping     |    |             |
|                   |                              |    |             |
|                   | § 24.3 Requirements for the  |    |             |
|                   | record format                |    |             |
|                   |                              |    |             |
|                   | § 24.4 Requirements for the  |    |             |
|                   | retention of records by the  |    |             |
|                   | emission sources             |    |             |
+-------------------+------------------------------+----+-------------+
| 25.1              | § 25.1 Requirements for the  | no | entire      |
| Upset/Breakdown,  | excess emissions caused by   |    | facility    |
| Malfunctions      | upset/breakdown and          |    |             |
|                   | malfunctions                 |    |             |
+-------------------+------------------------------+----+-------------+
| 25.2              | § 25.2 Reporting and         | y  | entire      |
| Upset/Breakdown,  | Consultation                 | es | facility    |
| Malfunctions      |                              |    |             |
+-------------------+------------------------------+----+-------------+
| 26\. Emission of  | § 26.1 Limit on opacity ( 20 | y  | entire      |
| Visible Air       | percent for 3 minutes in a   | es | facility    |
| Contaminants      | 60-minute period)            |    |             |
+-------------------+------------------------------+----+-------------+
| 28\. Fuel Burning | Emission Limitations for PM  | y  | entire      |
| Equipment         |                              | es | facility    |
+-------------------+------------------------------+----+-------------+
| 29\. Sulfur       | Sulfur content shall be      | no | CTGs        |
| Contents of Fuel  | equal to or less than 0.05   |    |             |
| Oil               | percent sulfur by weight     |    |             |
+-------------------+------------------------------+----+-------------+
| 40\. Prohibitions | § 40.1 Prohibitions          | no | entire      |
| of Nuisance       |                              |    | facility    |
| Conditions        |                              |    |             |
+-------------------+------------------------------+----+-------------+
| 41\. Fugitive     | § 41.1 Prohibitions          | y  | entire      |
| Dust              |                              | es | facility    |
+-------------------+------------------------------+----+-------------+
| 42\. Open Burning | § 42.2                       | no | entire      |
|                   |                              |    | facility    |
+-------------------+------------------------------+----+-------------+
| 43\. Odors In the | § 43.1 Prohibitions coded as | no | entire      |
| Ambient Air       | Section 29                   |    | facility    |
+-------------------+------------------------------+----+-------------+
| 49\. Emission     | Local enforcement only all   | no | entire      |
| Standards for     | subsections                  |    | facility    |
| Boilers and Steam |                              |    |             |
| Generators        |                              |    |             |
| Burning Fossil    |                              |    |             |
| Fuels             |                              |    |             |
+-------------------+------------------------------+----+-------------+
| 55\.              | all subsections              | no | entire      |
| Preconstruction   |                              |    | facility    |
| Review for New or |                              |    |             |
| Modified          |                              |    |             |
| Stationary        |                              |    |             |
| Sources in the    |                              |    |             |
| 8-hour Ozone      |                              |    |             |
| Nonattainment     |                              |    |             |
| Area              |                              |    |             |
+-------------------+------------------------------+----+-------------+
| 60\. Evaporation  | all subsections              | y  | entire      |
| and Leakage       |                              | es | facility    |
+-------------------+------------------------------+----+-------------+
| 70\. Emergency    | all subsections              | y  | entire      |
| Procedures        |                              | es | facility    |
+-------------------+------------------------------+----+-------------+
| 80\.              | all subsections              | y  | entire      |
| Circumvention     |                              | es | facility    |
+-------------------+------------------------------+----+-------------+

## B. Federally Applicable Regulations

**[40 CFR PART 60-STANDARDS OF PERFORMANCE FOR NEW STATIONARY
SOURCES]{.underline}**

#### Subpart A - General Provisions

**40 CFR § 60.7**-**Notification and record keeping** requires
notification to DAQEM of modifications, opacity testing, records of
malfunctions of process equipment and/or continuous monitoring device,
CEMS data, and performance test data. These requirements are found in
the Part 70 OP in Sections III-D, III-E, III-F, III-G and III-H.

DAQEM requires records to be maintained for five years, a more stringent
requirement than the two years required by § 60.7.

**40 CFR § 60.8-Performance tests** requirements are found in the Part
70 OP in Section III-F. Notice of intent to test, the applicable test
methods, acceptable test method operating conditions, and the
requirement for three runs are outlined in this regulation. DAQEM
requirements for initial performance testing are identical to § 60.8.
DAQEM also requires periodic performance testing on emission units based
upon throughput or usage. More discussion is in this document below.

[]{.mark}

**40 CFR § 60.11-Compliance with standards and maintenance
requirements.**

[]{.mark}

\(a\) Compliance with standards in this part, other than opacity
standards, shall be determined only by performance tests established by
§ 60.8, unless otherwise specified in the applicable standard.

**Discussion:** Subpart GG also requires fuel monitoring and sampling to
meet a standard. Subpart GG requirements are addressed in the Part 70
permit.

\(b\) Compliance with opacity standards in this part shall be determined
by conducting observations in accordance with Reference Method 9 in
appendix A of this part, any alternative method that is approved by the
Administrator, or as provided in paragraph (e)(5) of this section. For
purposes of determining initial compliance, the minimum total time of
observations shall be 3 hours (30 6-minute averages) for the performance
test or other set of observations (meaning those fugitive-type emission
sources subject only to an opacity standard).

**Discussion:** The opacity standard for the combustion turbines is zero
percent, except for three minutes in any 60-minute period where the
opacity shall not exceed 20 percent. A Method 9 test shall be performed
initially and every two years thereafter or after every 10,000 hours of
operation per Condition III-F-5 of the Part 70 operating permit.

[]{.mark}

\(c\) The opacity standards set forth in this part shall apply at all
times except during periods of startup, shutdown, malfunction, and as
otherwise provided in the applicable standard.

[]{.mark}

**Discussion:** Section 26 of the AQR is more stringent than the federal
opacity standards, setting a maximum of 20 percent obscurity except for
three minutes in any 60-minute period.

[]{.mark}

\(d\) At all times, including periods of startup, shutdown, and
malfunction, owners and operators shall, to the extent practicable,
maintain and operate any affected facility 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.

**Discussion:** Nevada Power Company shall operate in a manner
consistent with this section of the regulation.

[]{.mark}

**40 CFR § 60.12- Circumvention** prohibition is Condition I-A-27 in the
Part 70 OP. This is also local rule § 80.1.

**40 CFR § 60.13-Monitoring requirements.**

This section requires that CEMS meet Appendix B and Appendix F standards
of operation, testing and performance criteria. Section III-E of the
Part 70 OP contains the CEMS conditions and citations to Appendix B and
F. In addition, the QA plan approved for the CEMS follows the
requirements outlined including span time and recording time.

[]{.mark}

Subpart GG-Standards of Performance for Stationary Gas Turbines

**40 CFR § 60.330-Applicability and designation of affected facility.**

\(a\) The provisions of this subpart are applicable to all stationary
gas turbines with a heat input at peak load equal to or greater than
10.70 gigajoules per hour (ten MMBtu per hour), based on the lower
heating value of the fuel fired.

\(b\) Any facility under paragraph (a) of this section which commences
construction, modification, or reconstruction after October 3, 1977, is
subject to the requirements of this part except as provided in
paragraphs (e) and (j) of § 60.332. \[44 FR 52798, Sept. 10, 1979, as
amended at 52 FR 42434, Nov. 5, 1987\]

**Discussion:** Construction began on the two combined-cycle turbines in
2002. The lower heating value of the natural gas fuel is above the ten
MMBtu per hour threshold. Subpart GG shall apply to both EUs: A01 and
A03.

[]{.mark}

[]{.mark}

**40 CFR § 60.332-Standard for nitrogen oxides. (NO~X~ limits using the
F formula)**

(a) On and after the date on which the performance test required by §
    60.8 is completed, every owner or operator subject to the provisions
    of this subpart as specified in paragraphs (b), (c), and (d) of this
    section shall comply with one of the following, except as provided
    in paragraphs (e), (f), (g), (h), (i), (j), (k), and (l) of this
    section.

    1.  No owner or operator subject to the provisions of this subpart
        shall cause to be discharged into the atmosphere from any
        stationary gas turbine, any gases which contain nitrogen oxides
        in excess of:

STD = 0.0075 x 14.4/Y + F

where:

> STD = allowable NO~x~ emissions (percent by volume at 15 percent
> oxygen and on a dry basis).
>
> Y = manufacturer's rated heat rate at manufacturer's rated load
> (kilojoules per watt hour) or, actual measured heat rate based on
> lower heating value of fuel as measured at actual peak load for the
> facility. The value of Y shall not exceed 14.4 kilojoules per watt
> hour.
>
> F = NO~x~ emission allowance for fuel-bound nitrogen as defined in
> paragraph (a)(3) of this section.

**Discussion:** Per the application for the Title V operating permit,
the NSPS NO~X~ emission limit is calculated with a heat rate of 1.0548
kilojoules/Btu. Assuming that there are 8.29 Btus per watt-hour, the
value of Y in this equation is 8.74 kilojoules per watt-hour. Because
the facility uses PUC natural gas, the F factor is zero. Therefore:

0.0075 x 14.4/8.74 + 0 = 0.0124 percent by volume at 15 percent oxygen

0.0124 volume% x (10,000 ppm/volume%) = 124 ppmv NO~X~ at 15 percent
oxygen

Nevada Power Company shall comply with this standard.

[]{.mark}

**40 CFR § 60.333-Standard for sulfur dioxide.**

On and after the date on which the performance test required to be
conducted by § 60.8 is completed, every owner or operator subject to the
provision of this subpart shall comply with one or the other of the
following conditions:

(a) No owner or operator subject to the provisions of this subpart shall
    cause to be discharged into the atmosphere from any stationary gas
    turbine any gases which contain sulfur dioxide in excess of 0.015
    percent by volume at 15 percent oxygen and on a dry basis.

(b) No owner or operator subject to the provisions of this subpart shall
    burn in any stationary gas turbine any fuel which contains sulfur in
    excess of 0.8 percent by weight.

**Discussion:** The use of pipeline quality PUC natural gas will satisfy
this regulation. This is stipulated in Condition III-C-6 of the Part 70
operating permit. The sulfur is limited to 0.75 grains per 100 dry
standard cubic feet in Condition III-D-4.

[]{.mark}

**40 CFR § 60.334-Monitoring of operations.**

\(b\) The owner or operator of any stationary gas turbine subject to the
provisions of this subpart shall monitor sulfur content of the fuel
being fired in the turbine. The frequency of determination of these
values shall be as follows:

> \(2\) If the turbine is supplied its fuel without intermediate bulk
> storage the values shall be determined and recorded daily. Owners,
> operators or fuel vendors may develop custom schedules for
> determination of the values based on the design and operation of the
> affected facility and the characteristics of the fuel supply. These
> custom schedules shall be substantiated with data and must be approved
> by the Administrator before they can be used to comply with paragraph
> (b) of this section.

**Discussion:** This requirement is stipulated in Condition III-D-4 of
the Part 70 operating permit. Sulfur content shall be verified annually
and based on data from the gas supplier.

[]{.mark}

**40 CFR § 60.335-Test methods and procedures.**

\(b\) In conducting the performance tests required in § 60.8, the owner
or operator shall use as reference methods and procedures the test
methods in appendix A of this part or other methods and procedures as
specified in this section, except as provided for in § 60.8(b).
Acceptable alternative methods and procedures are given in paragraph (f)
of this section.

\(c\) The owner or operator shall determine compliance with the nitrogen
oxides and sulfur dioxide standards in §§ 60.332 and 60.333(a) as
follows:

1.  The monitoring device of § 60.334(a) shall be used to determine the
    fuel consumption and the water-to-fuel ratio necessary to comply
    with § 60.332 at 30, 50, 75, and 100 percent of peak load or at four
    points in the normal operating range of the gas turbine, including
    the minimum point in the range and peak load. All loads shall be
    corrected to ISO conditions using the appropriate equations supplied
    by the manufacturer.

2.  Method 20 shall be used to determine the nitrogen oxides, sulfur
    dioxide, and oxygen concentrations. The span values shall be 100 ppm
    of nitrogen oxide and 21 percent oxygen. The NO~X~ emissions shall
    be determined at each of the load conditions specified in paragraph
    (c)(2) of this section.

**Discussion:** These requirements are found in the conditions for
performance testing found in Section III-F of the Part 70 OP.

#### 

#### Subpart Da- Standards of Performance for Electric Utility Steam Generating Units for Which Construction is Commenced After September 18, 1978

### 40 CFR § 60.40a -- Applicability

\(a\) The affected facility to which this subpart applies is each
electric utility steam generating unit:

> \(1\) That is capable of combusting more than 73 megawatts (250
> million Btu/hour) heat input of fossil fuel (either alone or in
> combination with any other fuel); and
>
> \(2\) For which construction or modification is commenced after
> September 18, 1978.

\(b\) Unless and until subpart GG of this part extends the applicability
of subpart GG of this part to electric utility steam generators, this
subpart applies to electric utility combined cycle gas turbines that are
capable of combusting more than 73 megawatts (250 million Btu/hour) heat
input of fossil fuel in the steam generator. Only emissions resulting
from combustion of fuels in the steam generating unit are subject to
this subpart. (The gas turbine emissions are subject to subpart GG of
this part.)

**Discussion:** The duct burners (EUs: A02 and A04, inclusive) are
subject to the provisions of this subpart. They each have a rated
capacity of 530 MMBtu per hour.

### 40 CFR § 60.42a -- Standard for Particulate Matter

\(a\) On and after the date on which the performance test required to be
conducted under Sec. 60.8 is completed, no owner or operator subject to
the provisions of this subpart shall cause to be discharged into the
atmosphere from any affected facility any gases which contain
particulate matter in excess of:

> \(1\) 13 ng/J (0.03 lb/million Btu) heat input derived from the
> combustion of solid, liquid, or gaseous fuel;

**Discussion:** The manufacturer's performance data for the duct burners
state that particulate emissions from the combustion of natural gas will
yield 0.01 pounds per MMBtu. Nevada Power Company shall be in compliance
with this regulation.

\(b\) On and after the date the particulate matter performance test
required to be conducted under Sec. 60.8 is completed, no owner or
operator subject to the provisions of this subpart shall cause to be
discharged into the atmosphere from any affected facility any gases
which exhibit greater than 20 percent opacity (6-minute average), except
for one 6-minute period per hour of not more than 27 percent opacity.

**Discussion:** Condition III-C-8 in the Part 70 operating permit states
that there will zero opacity from each turbine/duct burner stack except
for three minutes in any 60-minute period when visible emissions shall
not exceed 20 percent. This is more stringent than the NSPS limits.

### 

### 40 CFR § 60.43a -- Standard for Sulfur Dioxide

\(b\) On and after the date on which the initial performance test
required to be conducted under § 60.8 is completed, no owner or operator
subject to the provisions of this subpart shall cause to be discharged
into the atmosphere from any affected facility which combusts liquid or
gaseous fuels (except for liquid or gaseous fuels derived from solid
fuels and as provided under paragraphs (e) or (h) of this section), any
gases which contain sulfur dioxide in excess of:

(1) 340 ng/J (0.80 lb/million Btu) heat input and 10 percent of the
    potential combustion concentration (90 percent reduction), or

(2) 100 percent of the potential combustion concentration (zero percent
    reduction) when emissions are less than 86 ng/J (0.20 lb/million
    Btu) heat input.

\(g\) Compliance with the emission limitation and percent reduction
requirements under this section are both determined on a 30-day rolling
average basis except as provided under paragraph (c) of this section.

**Discussion:** The manufacturer's performance data for the duct burners
states that particulate emissions from the combustion of natural gas
will yield 0.0006 pounds per MMBtu. Nevada Power Company shall be in
compliance with this standard.

### 40 CFR § 60.44a -- Standard for Nitrogen Oxides

\(a\) On and after the date on which the performance test required to be
conducted by § 60.8 is completed, no owner or operator subject to the
provisions of this subpart shall cause to be discharged into the
atmosphere from any affected facility any gases which contain nitrogen
oxides, expressed as NO~2~ in excess of:

> \(1\) 86 nanograms per joule heat input (0.20 lb per million Btu)
> derived from gaseous fossil fuel.

**Discussion:** According to the manufacturer, the duct burners operate
at a full load input of 530 MMBtu per hour HHV and will contribute
approximately 4.85 pounds per hour of NO~X~ emissions. Therefore, the
emission rate can be calculated as follows:

4.85 pounds/hour / 530 MMBtu/hour = 0.01 pounds NO~X~ per MMBtu

Nevada Power Company shall be in compliance with this standard.

### 40 CFR § 60.46a -- Compliance Provisions

\(c\) The particulate matter emission standards under § 60.42a and the
nitrogen oxides emission standards under § 60.44a apply at all times
except during periods of startup, shutdown, or malfunction. The sulfur
dioxide emission standards under § 60.43a apply at all times except
during periods of startup, shutdown, or when both emergency conditions
exist and the procedures under paragraph (d) of this section are
implemented.

**Discussion:** Nevada Power Company has separate emission standards
during startup and shutdown. They are outlined in Table III-A-3 in the
Part 70 operating permit.

\(e\) After the initial performance test required under § 60.8,
compliance with the sulfur dioxide emission limitations and percentage
reduction requirements under § 60.43a and the nitrogen oxides emission
limitations under § 60.44a is based on the average emission rate for 30
successive operating days. A separate performance test is completed at
the end of each operating day after the initial performance test, and a
new 30 day average emission rate for both sulfur dioxide and nitrogen
oxides and a new percent reduction for sulfur dioxide are calculated to
show compliance with the standards.

\(f\) For the initial performance test required under § 60.8, compliance
with the sulfur dioxide emission limitations and percent reduction
requirements under § 60.43a and the nitrogen oxides emission limitation
under § 60.44a is based on the average emission rates for sulfur
dioxide, nitrogen oxides, and percent reduction for sulfur dioxide for
the first 30 successive boiler operating days. The initial performance
test is the only test in which at least 30 days prior notice is required
unless otherwise specified by the Administrator. The initial performance
test is to be scheduled so that the first boiler operating day of the 30
successive boiler operating days is completed within 60 days after
achieving the maximum production rate at which the affected facility
will be operated, but not later than 180 days after initial startup of
the facility.

\(g\) Compliance is determined by calculating the arithmetic average of
all hourly emission rates for SO2 and NOX for the 30 successive boiler
operating days, except for data obtained during startup, shutdown,
malfunction (NOX only), or emergency conditions (SO2 only). Compliance
with the percentage reduction requirement for SO2 is determined based on
the average inlet and average outlet SO2 emission rates for the 30
successive boiler operating days.

\(h\) If an owner or operator has not obtained the minimum quantity of
emission data as required under § 60.47a of this subpart, compliance of
the affected facility with the emission requirements under §§ 60.43a and
60.44a of this subpart for the day on which the 30-day period ends may
be determined by the Administrator by following the applicable
procedures in section 7 of Method 19.

**Discussion:** Nevada Power Company has completed all compliance
demonstrations and has demonstrated compliance with all applicable
emission standards for NO~X~ and SO~2~.

\(j\) *Compliance provisions for duct burners subject to §
60.44a(a)(1).* To determine compliance with the emissions limits for NOX
required by § 60.44a(a) for duct burners used in combined cycle systems,
either of the procedures described in paragraph (j)(1) or (2) of this
section may be used:

> \(1\) The owner or operator of an affected duct burner shall conduct
> the performance test required under § 60.8 using the appropriate
> methods in appendix A of this part. Compliance with the emissions
> limits under § 60.44a(a)(1) is determined on the average of three
> (nominal 1-hour) runs for the initial and subsequent performance
> tests. During the performance test, one sampling site shall be located
> in the exhaust of the turbine prior to the duct burner. A second
> sampling site shall be located at the outlet from the heat recovery
> steam generating unit. Measurements shall be taken at both sampling
> sites during the performance test; or
>
> \(2\) The owner or operator of an affected duct burner may elect to
> determine compliance by using the continuous emission monitoring
> system specified under § 60.47a for measuring NOX and oxygen and meet
> the requirements of § 60.47a. Data from a CEMS certified (or
> recertified) according to the provisions of 40 CFR 75.20, meeting the
> QA and QC requirements of 40 CFR 75.21, and validated according to 40
> CFR 75.23 may be used. The sampling site shall be located at the
> outlet from the steam generating unit. The NOX emission rate at the
> outlet from the steam generating unit shall constitute the NOX
> emission rate from the duct burner of the combined cycle system.

**Discussion:** Nevada Power Company employs the use of CEMS on each of
the turbine stacks to monitor NO~X~ emissions. The measurements to be
taken are outlined in Condition III-E-1 in the Part 70 operating permit.

### 40 CFR § 60.47a -- Emission Monitoring

\(a\) The owner or operator of an affected facility shall install,
calibrate, maintain, and operate a continuous monitoring system, and
record the output of the system, for measuring the opacity of emissions
discharged to the atmosphere, except where gaseous fuel is the only fuel
combusted. If opacity interference due to water droplets exists in the
stack (for example, from the use of an FGD system), the opacity is
monitored upstream of the interference (at the inlet to the FGD system).
If opacity interference is experienced at all locations (both at the
inlet and outlet of the sulfur dioxide control system), alternate
parameters indicative of the particulate matter control system's
performance are monitored (subject to the approval of the
Administrator).

**Discussion:** The duct burners combust only natural gas; therefore,
continuous opacity monitoring system (COMS) are not required.

\(b\) The owner or operator of an affected facility shall install,
calibrate, maintain, and operate a continuous monitoring system, and
record the output of the system, for measuring sulfur dioxide emissions,
except where natural gas is the only fuel combusted, as follows:

**Discussion:** The duct burners combust only natural gas; therefore,
SO~2~ CEMS are not required.

\(c\) (1) The owner or operator of an affected facility shall install,
calibrate, maintain, and operate a continuous monitoring system, and
record the output of the system, for measuring nitrogen oxides emissions
discharged to the atmosphere; or

> \(2\) If the owner or operator has installed a nitrogen oxides
> emission rate continuous emission monitoring system (CEMS) to meet the
> requirements of part 75 of this chapter and is continuing to meet the
> ongoing requirements of part 75 of this chapter, that CEMS may be used
> to meet the requirements of this section, except that the owner or
> operator shall also meet the requirements of § 60.49a. Data reported
> to meet the requirements of § 60.49a shall not include data
> substituted using the missing data procedures in subpart D of part 75
> of this chapter, nor shall the data have been bias adjusted according
> to the procedures of part 75 of this chapter.

**Discussion:** Nevada Power Company is subject to the requirements of
40 CFR 75; therefore, the data acquired by the NO~X~ CEMS are allowed to
be used to show compliance with both 40 CFR 60 Subpart Da and 40 CFR 75.
The reporting requirements are outlined in Section III-H of the Part 70
operating permit.

\(d\) The owner or operator of an affected facility shall install,
calibrate, maintain, and operate a continuous monitoring system, and
record the output of the system, for measuring the oxygen or carbon
dioxide content of the flue gases at each location where sulfur dioxide
or nitrogen oxides emissions are monitored.

**Discussion:** Nevada Power Company has installed a diluent oxygen
CEMS. Monitoring requirements are outlined in Section III-E of the Part
70 operating permit.

\(e\) The continuous monitoring systems under paragraphs (b), (c), and
(d) of this section are operated and data recorded during all periods of
operation of the affected facility including periods of startup,
shutdown, malfunction or emergency conditions, except for continuous
monitoring system breakdowns, repairs, calibration checks, and zero and
span adjustments.

\(f\) The owner or operator shall obtain emission data for at least 18
hours in at least 22 out of 30 successive boiler operating days. If this
minimum data requirement cannot be met with a continuous monitoring
system, the owner or operator shall supplement emission data with other
monitoring systems approved by the Administrator or the reference
methods and procedures as described in paragraph (h) of this section.

\(g\) The 1-hour averages required under paragraph § 60.13(h) are
expressed in ng/J (lb/million Btu) heat input and used to calculate the
average emission rates under § 60.46a. The 1-hour averages are
calculated using the data points required under § 60.13(b). At least two
data points must be used to calculate the 1-hour averages.

\(h\) When it becomes necessary to supplement continuous monitoring
system data to meet the minimum data requirements in paragraph (f) of
this section, the owner or operator shall use the reference methods and
procedures as specified in this paragraph. Acceptable alternative
methods and procedures are given in paragraph (j) of this section.

> \(1\) Method 6 shall be used to determine the SO2 concentration at the
> same location as the SO2 monitor. Samples shall be taken at 60-minute
> intervals. The sampling time and sample volume for each sample shall
> be at least 20 minutes and 0.020 dscm (0.71 dscf). Each sample
> represents a 1-hour average.
>
> \(2\) Method 7 shall be used to determine the NOX concentration at the
> same location as the NOX monitor. Samples shall be taken at 30-minute
> intervals. The arithmetic average of two consecutive samples
> represents a 1-hour average.
>
> \(3\) The emission rate correction factor, integrated bag sampling and
> analysis procedure of Method 3B shall be used to determine the O2 or
> CO2 concentration at the same location as the O2 or CO2 monitor.
> Samples shall be taken for at least 30 minutes in each hour. Each
> sample represents a 1-hour average.
>
> \(4\) The procedures in Method 19 shall be used to compute each 1-hour
> average concentration in ng/J (1b/million Btu) heat input.

\(i\) The owner or operator shall use methods and procedures in this
paragraph to conduct monitoring system performance evaluations under
60.13(c) and calibration checks under 60.13(d). Acceptable alternative
methods and procedures are given in paragraph (j) of this section.

> \(1\) Methods 3B, 6, and 7 shall be used to determine O2, SO2, and NOX
> concentrations, respectively.
>
> \(2\) SO2 or NOX (NO), as applicable, shall be used for preparing the
> calibration gas mixtures (in N2, as applicable) under Performance
> Specification 2 of appendix B of this part.
>
> \(3\) For affected facilities burning only fossil fuel, the span value
> for a continuous monitoring system for measuring opacity is between 60
> and 80 percent and for a continuous monitoring system measuring
> nitrogen oxides is determined as follows:
>
> Fossil fuel Span value for nitrogen oxides (ppm) Gas
> \...\...\...\...\...\...\...\...\...\...\...\...\....500
>
> \(4\) All span values computed under paragraph (b)(3) of this section
> for burning combinations of fossil fuels are rounded to the nearest
> 500 ppm.
>
> \(5\) For affected facilities burning fossil fuel, alone or in
> combination with non-fossil fuel, the span value of the sulfur dioxide
> continuous monitoring system at the inlet to the sulfur dioxide
> control device is 125 percent of the maximum estimated hourly
> potential emissions of the fuel fired, and the outlet of the sulfur
> dioxide control device is 50 percent of maximum estimated hourly
> potential emissions of the fuel fired.

\(j\) The owner or operator may use the following as alternatives to the
reference methods and procedures specified in this section:

> \(1\) For Method 6, Method 6A or 6B (whenever Methods 6 and 3 or 3B
> data are used) or 6C may be used. Each Method 6B sample obtained over
> 24 hours represents 24 1-hour averages. If Method 6A or 6B is used
> under paragraph (i) of this section, the conditions under §
> 60.46(d)(1) apply; these conditions do not apply under paragraph (h)
> of this section.
>
> \(2\) For Method 7, Method 7A, 7C, 7D, or 7E may be used. If Method
> 7C, 7D, or 7E is used, the sampling time for each run shall be 1 hour.
>
> \(3\) For Method 3, Method 3A or 3B may be used if the sampling time
> is 1 hour.
>
> \(4\) For Method 3B, Method 3A may be used.

\(k\) The procedures specified in paragraphs (k)(1) through (3) of this
section shall be used to determine gross output for sources
demonstrating compliance with the output-based standard under §
60.44a(d)(1).

> \(1\) The owner or operator of an affected facility with electricity
> generation shall install, calibrate, maintain, and operate a
> wattmeter; measure gross electrical output in megawatt-hour on a
> continuous basis; and record the output of the monitor.
>
> \(2\) The owner or operator of an affected facility with process steam
> generation shall install, calibrate, maintain, and operate meters for
> steam flow, temperature, and pressure; measure gross process steam
> output in joules per hour (or Btu per hour) on a continuous basis; and
> record the output of the monitor.
>
> \(3\) For affected facilities generating process steam in combination
> with electrical generation, the gross energy output is determined from
> the gross electrical output measured in accordance with paragraph
> (k)(1) of this section plus 50 percent of the gross thermal output of
> the process steam measured in accordance with paragraph (k)(2) of this
> section.

\(l\) The owner or operator of an affected facility demonstrating
compliance with the output-based standard under § 60.44a(d)(1) shall
install, certify, operate, and maintain a continuous flow monitoring
system meeting the requirements of Performance Specification 6 of
appendix B and procedure 1 of appendix F of this subpart, and record the
output of the system, for measuring the flow of exhaust gases discharged
to the atmosphere; or (m) Alternatively, data from a continuous flow
monitoring system certified according to the requirements of 40 CFR
75.20, meeting the applicable quality control and quality assurance
requirements of 40 CFR 75.21, and validated according to 40 CFR 75.23,
may be used.

**Discussion:** Monitoring requirements are outlined in Section III-E of
the Part 70 operating permit.

\(n\) Gas-fired and oil-fired units. The owner or operator of an
affected unit that qualifies as a gas-fired or oil-fired unit, as
defined in 40 CFR 72.2, may use, as an alternative to the requirements
specified in either paragraph (l) or (m) of this section, a fuel flow
monitoring system certified and operated according to the requirements
of appendix D of 40 CFR part 75.

\(o\) The owner or operator of a duct burner, as described in § 60.41a,
which is subject to the NOX standards of § 60.44a(a)(1) or (d)(1) is not
required to install or operate a continuous emissions monitoring system
to measure NOX emissions; a wattmeter to measure gross electrical
output; meters to measure steam flow, temperature, and pressure; and a
continuous flow monitoring system to measure the flow of exhaust gases
discharged to the atmosphere.

**Discussion:** The duct burners exhaust through the same stack as the
combustion turbines; therefore, the monitors required for monitoring
turbine emissions will also monitor duct burner emissions.

**40 CFR § 60.48a -- Compliance Determination Procedures and Methods**

The compliance demonstration for this facility is discussed in Section
III-D of the Part 70 operating permit.

**40 CFR § 60.49a -- Reporting Requirements** are discussed in Section
III-H of the Part 70 operating permit.

**[40 CFR PART 64-COMPLIANCE ASSURANCE MONITORING]{.underline}**

**40 CFR § 64.2 -- Applicability**

\(a\) General applicability. Except for backup utility units that are
exempt under paragraph (b)(2) of this section, the requirements of this
part shall apply to a pollutant-specific emissions unit at a major
source that is required to obtain a part 70 or 71 permit if the unit
satisfies all of the following criteria:

> \(1\) The unit is subject to an emission limitation or standard for
> the applicable regulated air pollutant (or a surrogate thereof), other
> than an emission limitation or standard that is exempt under paragraph
> (b)(1) of this section;
>
> \(2\) The unit uses a control device to achieve compliance with any
> such emission limitation or standard; and
>
> \(3\) The unit has potential pre-control device emissions of the
> applicable regulated air pollutant that are equal to or greater than
> 100 percent of the amount, in tons per year, required for a source to
> be classified as a major source. For purposes of this paragraph,
> ''potential pre-control device emissions'' shall have the same meaning
> as ''potential to emit,'' as defined in § 64.1, except that emission
> reductions achieved by the applicable control device shall not be
> taken into account.

\(b\) Exemptions

> \(1\) Exempt emission limitations or standards. The requirements of
> this part shall not apply to any of the following emission limitations
> or standards:
>
> \(i\) Emission limitations or standards proposed by the Administrator
> after November 15, 1990 pursuant to section 111 or 112 of the Act.
>
> \(ii\) Stratospheric ozone protection requirements under title VI of
> the Act.
>
> \(iii\) Acid Rain Program requirements pursuant to sections 404, 405,
> 406, 407(a), 407(b), or 410 of the Act.
>
> \(iv\) Emission limitations or standards or other applicable
> requirements that apply solely under an emissions trading program
> approved or promulgated by the Administrator under the Act that allows
> for trading emissions within a source or between sources.
>
> \(v\) An emissions cap that meets the requirements specified in §
> 70.4(b)(12) or § 71.6(a)(13)(iii) of this chapter.
>
> \(vi\) Emission limitations or standards for which a part 70 or 71
> permit specifies a continuous compliance determination method, as
> defined in § 64.1. The exemption provided in this paragraph (b)(1)(vi)
> shall not apply if the applicable compliance method includes an
> assumed control device emission reduction factor that could be
> affected by the actual operation and maintenance of the control device
> (such as a surface coating line controlled by an incinerator for which
> continuous compliance is determined by calculating emissions on the
> basis of coating records and an assumed control device efficiency
> factor based on an initial performance test; in this example, this
> part would apply to the control device and capture system, but not to
> the remaining elements of the coating line, such as raw material
> usage).

**Discussion:** Nevada Power Company is major for PM~10~, NO~X~, CO, and
NH~3~. Control devices are used on the combustion turbines/duct heaters
(EUs: A01-A04) for NO~X~ and CO; therefore, PM~10~ and NH~3~ emissions
from the turbines are not subject to CAM. There are no control devices
on the fire pump (EU: A05), emergency generator (EU: A06) or cooling
tower (EU: A07) so these emission units are not subject to CAM.

The turbines at Nevada Power Company are subject to the NO~X~ emissions
limits of 40 CFR 60 Subpart GG, which was promulgated in 1979;
therefore, the exemption listed in § 64.2(b)(1)(i) does not apply.
However, the facility is subject to the provisions of the acid rain
program per § 64.2(b)(1)(iii). This qualifies the NO~x~ emissions from
the turbines at Nevada Power Company for an exemption from compliance
assurance monitoring (CAM).

The turbines at Nevada Power Company are subject to the CO emission
limits presented in the facility's ATC/OP. There are no promulgated NSPS
or DAQEM emission limits; therefore, the exemption listed in §
64.2(b)(1)(i) does not apply. Because none of the exemptions in §
64.2(b) applies to the CO emissions at this facility, the turbines at
Nevada Power Company are subject to CAM for CO.

Nevada Power Company shall comply with the CAM rule through the CO CEMS
that are installed on the turbine exhaust stacks.

**[40 CFR PART 72-ACID RAIN PERMITS REGULATION]{.underline}**

**Subpart A -- Acid Rain Program General Provisions**

**40 CFR § 72.6 -- Applicability**

\(a\) Each of the following units shall be an affected unit, and any
source that includes such a unit shall be an affected source, subject to
the requirements of the Acid Rain Program:

> \(1\) unit listed in table 1 of § 73.10(a) of this chapter.
>
> \(2\) A unit that is listed in table 2 or 3 of § 73.10 of this chapter
> and any other existing utility unit, except a unit under paragraph (b)
> of this section.
>
> \(3\) A utility unit, except a unit under paragraph (b) of this
> section, that:
>
> \(i\) Is a new unit; or
>
> \(ii\) Did not serve a generator with a nameplate capacity greater
> than 25 MWe on November 15, 1990 but serves such a generator after
> November 15, 1990.
>
> \(iii\) Was a simple combustion turbine on November 15, 1990 but adds
> or uses auxiliary firing after November 15, 1990;
>
> \(iv\) Was an exempt cogeneration facility under paragraph (b)(4) of
> this section but during any three calendar year period after November
> 15, 1990 sold, to a utility power distribution system, an annual
> average of more than one-third of its potential electrical output
> capacity and more than 219,000 MWe-hrs electric output, on a gross
> basis;
>
> \(v\) Was an exempt qualifying facility under paragraph (b)(5) of this
> section but, at any time after the later of November 15, 1990 or the
> date the facility commences commercial operation, fails to meet the
> definition of qualifying facility;
>
> \(vi\) Was an exempt IPP under paragraph (b)(6) of this section but,
> at any time after the later of November 15, 1990 or the date the
> facility commences commercial operation, fails to meet the definition
> of independent power production facility; or
>
> \(vii\) Was an exempt solid waste incinerator under paragraph (b)(7)
> of this section but during any three calendar year period after
> November 15, 1990 consumes 20 percent or more (on a Btu basis) fossil
> fuel.

**Discussion:** Nevada Power Company is defined as a utility unit in the
definitions for Part 72; therefore, the provisions of this regulation
apply.

**40 CFR § 72.9 -- Standard Requirements**

\(a\) *Permit Requirements.*

> \(1\) The designated representative of each affected source and each
> affected unit at the source shall:
>
> \(i\) Submit a complete Acid Rain permit application (including a
> compliance plan) under this part in accordance with the deadlines
> specified in § 72.30;
>
> \(ii\) Submit in a timely manner a complete reduced utilization plan
> if required under § 72.43; and
>
> \(iii\) Submit in a timely manner any supplemental information that
> the permitting authority determines is necessary in order to review an
> Acid Rain permit application and issue or deny an Acid Rain permit.
>
> \(2\) The owners and operators of each affected source and each
> affected unit at the source shall:
>
> \(i\) Operate the unit in compliance with a complete Acid Rain permit
> application or a superseding Acid Rain permit issued by the permitting
> authority; and
>
> \(ii\) Have an Acid Rain Permit.

\(b\) *Monitoring Requirements.*

> \(1\) The owners and operators and, to the extent applicable,
> designated representative of each affected source and each affected
> unit at the source shall comply with the monitoring requirements as
> provided in part 75 of this chapter.
>
> \(2\) The emissions measurements recorded and reported in accordance
> with part 75 of this chapter shall be used to determine compliance by
> the unit with the Acid Rain emissions limitations and emissions
> reduction requirements for sulfur dioxide and nitrogen oxides under
> the Acid Rain Program.
>
> \(3\) The requirements of part 75 of this chapter shall not affect the
> responsibility of the owners and operators to monitor emissions of
> other pollutants or other emissions characteristics at the unit under
> other applicable requirements of the Act and other provisions of the
> operating permit for the source.

\(c\) *Sulfur Dioxide Requirements.*

> \(1\) The owners and operators of each source and each affected unit
> at the source shall:
>
> \(i\) Hold allowances, as of the allowance transfer deadline, in the
> unit's compliance subaccount (after deductions under § 73.34(c) of
> this chapter) not less than the total annual emissions of sulfur
> dioxide for the previous calendar year from the unit; and
>
> \(ii\) Comply with the applicable Acid Rain emissions limitation for
> sulfur dioxide.
>
> \(2\) Each ton of sulfur dioxide emitted in excess of the Acid Rain
> emissions limitations for sulfur dioxide shall constitute a separate
> violation of the Act.
>
> \(3\) An affected unit shall be subject to the requirements under
> paragraph (c)(1) of this section as follows:
>
> \(i\) Starting January 1, 1995, an affected unit under § 72.6(a)(1);
>
> \(ii\) Starting on or after January 1, 1995 in accordance with §§
> 72.41 and 72.43, an affected unit under § 72.6(a) (2) or (3) that is a
> substitution or compensating unit;
>
> (iii)Starting January 1, 2000, an affected unit under § 72.6(a)(2)
> that is not a substitution or compensating unit; or
>
> (iv)Starting on the later of January 1, 2000 or the deadline for
> monitor certification under part 75 of this chapter, an affected unit
> under § 72.6(a)(3) that is not a substitution or compensating unit.
>
> \(4\) Allowances shall be held in, deducted from, or transferred among
> Allowance Tracking System accounts in accordance with the Acid Rain
> Program.
>
> \(5\) An allowance shall not be deducted, in order to comply with the
> requirements under paragraph (c)(1)(i) of this section, prior to the
> calendar year for which the allowance was allocated.
>
> \(6\) An allowance allocated by the Administrator under the Acid Rain
> Program is a limited authorization to emit sulfur dioxide in
> accordance with the Acid Rain Program. No provision of the Acid Rain
> Program, the Acid Rain permit application, the Acid Rain permit, or an
> exemption under §§ 72.7 or 72.8 and no provision of law shall be
> construed to limit the authority of the United States to terminate or
> limit such authorization.
>
> \(7\) An allowance allocated by the Administrator under the Acid Rain
> Program does not constitute a property right.

\(d\) *Nitrogen Oxides Requirements.* The owners and operators of the
source and each affected unit at the source shall comply with the
applicable Acid Rain emissions limitation for nitrogen oxides.

\(e\) *Excess Emissions Requirements.*

> \(1\) The designated representative of an affected unit that has
> excess emissions in any calendar year shall submit a proposed offset
> plan, as required under part 77 of this chapter.
>
> \(2\) The owners and operators of an affected unit that has excess
> emissions in any calendar year shall:
>
> \(i\) Pay without demand the penalty required, and pay upon demand the
> interest on that penalty, as required by part 77 of this chapter; and
>
> \(ii\) Comply with the terms of an approved offset plan, as required
> by part 77 of this chapter.

\(f\) *Recordkeeping and Reporting Requirements.*

> \(1\) Unless otherwise provided, the owners and operators of the
> source and each affected unit at the source shall keep on site at the
> source each of the following documents for a period of 5 years from
> the date the document is created. This period may be extended for
> cause, at any time prior to the end of 5 years, in writing by the
> Administrator or permitting authority.
>
> \(i\) The certificate of representation for the designated
> representative for the source and each affected unit at the source and
> all documents that demonstrate the truth of the statements in the
> certificate of representation, in accordance with § 72.24; *provided*
> that the certificate and documents shall be retained on site at the
> source beyond such 5-year period until such documents are superseded
> because of the submission of a new certificate of representation
> changing the designated representative.
>
> \(ii\) All emissions monitoring information, in accordance with part
> 75 of this chapter; *provided* that to the extent that part 75
> provides for a 3-year period for recordkeeping, the 3-year period
> shall apply.
>
> \(iii\) Copies of all reports, compliance certifications, and other
> submissions and all records made or required under the Acid Rain
> Program.
>
> \(iv\) Copies of all documents used to complete an Acid Rain permit
> application and any other submission under the Acid Rain Program or to
> demonstrate compliance with the requirements of the Acid Rain Program.
>
> \(2\) The designated representative of an affected source and each
> affected unit at the source shall submit the reports and compliance
> certifications required under the Acid Rain Program, including those
> under subpart I of this part and part 75 of this chapter.

\(g\) *Liability.*

> \(1\) Any person who knowingly violates any requirement or prohibition
> of the Acid Rain Program, a complete Acid Rain permit application, an
> Acid Rain permit, or an exemption under § 72.7 or § 72.8, including
> any requirement for the payment of any penalty owed to the United
> States, shall be subject to enforcement pursuant to section 113(c) of
> the Act.
>
> \(2\) Any person who knowingly makes a false, material statement in
> any record, submission, or report under the Acid Rain Program shall be
> subject to criminal enforcement pursuant to section 113(c) of the Act
> and 18 U.S.C. 1001.
>
> \(3\) No permit revision shall excuse any violation of the
> requirements of the Acid Rain Program that occurs prior to the date
> that the revision takes effect.
>
> \(4\) Each affected source and each affected unit shall meet the
> requirements of the Acid Rain Program.
>
> \(5\) Any provision of the Acid Rain Program that applies to an
> affected source (including a provision applicable to the designated
> representative of an affected source) shall also apply to the owners
> and operators of such source and of the affected units at the source.
>
> \(6\) Any provision of the Acid Rain Program that applies to an
> affected unit (including a provision applicable to the designated
> representative of an affected unit) shall also apply to the owners and
> operators of such unit. Except as provided under § 72.41 (substitution
> plans), § 72.42 (Phase I extension plans), § 72.43 (reduced
> utilization plans), § 72.44 (Phase II repowering extension plans), §
> 74.47 of this chapter (thermal energy plans), and § 76.11 of this
> chapter (NOX averaging plans), and except with regard to the
> requirements applicable to units with a common stack under part 75 of
> this chapter (including §§ 75.16, 75.17 and 75.18 of this chapter),
> the owners and operators and the designated representative of one
> affected unit shall not be liable for any violation by any other
> affected unit of which they are not owners or operators or the
> designated representative and that is located at a source of which
> they are not owners or operators or the designated representative.
>
> \(7\) Each violation of a provision of this part, parts 73, 74, 75,
> 76, 77, and 78 of this chapter, by an affected source or affected
> unit, or by an owner or operator or designated representative of such
> source or unit, shall be a separate violation of the Act.

\(h\) *Effect on Other Authorities.* No provision of the Acid Rain
Program, an Acid Rain permit application, an Acid Rain permit, or an
exemption under § 72.7 or § 72.8 shall be construed as:

> \(1\) Except as expressly provided in title IV of the Act, exempting
> or excluding the owners and operators and, to the extent applicable,
> the designated representative of an affected source or affected unit
> from compliance with any other provision of the Act, including the
> provisions of title I of the Act relating to applicable National
> Ambient Air Quality Standards or State Implementation Plans.
>
> \(2\) Limiting the number of allowances a unit can hold; *provided,*
> that the number of allowances held by the unit shall not affect the
> source's obligation to comply with any other provisions of the Act.
>
> \(3\) Requiring a change of any kind in any State law regulating
> electric utility rates and charges, affecting any State law regarding
> such State regulation, or limiting such State regulation, including
> any prudence review requirements under such State law.
>
> \(4\) Modifying the Federal Power Act or affecting the authority of
> the Federal Energy Regulatory Commission under the Federal Power Act.
>
> \(5\) Interfering with or impairing any program for competitive
> bidding for power supply in a State in which such program is
> established.

**Discussion:** Nevada Power Company has applied for all of the proper
permits under this regulation. An ORIS Code (#55841) for emission units
SGS1 and SGS2 (EUs: A01/A02, A03/A04) has been obtained. A Certificate
of Representation for Designated Representative has been registered with
Warren Kotzmann as the primary representative and William M. Simko as
the alternate representative.

**Subpart B -- Designated Representative**

Nevada Power Company has a Certificate of Representation for Designated
Representative on file. They have fulfilled all requirements under this
subpart.

**Subpart C -- Acid Rain Permit Applications**

Nevada Power Company has applied for an acid rain permit.

**Subpart D -- Acid Rain Compliance Plan and Compliance Options**

This subpart discusses the individual requirements necessary for a
complete compliance plan. A compliance plan exists for each combustion
turbine.

**Subpart E -- Acid Rain Permit Contents**

Nevada Power Company has applied for an acid rain permit, and it will
contain all information to demonstrate compliance with this subpart.

**[40 CFR PART 73 -- ACID RAIN SULFUR DIOXIDE ALLOWANCE
SYSTEM]{.underline}**

**Subpart A -- Background and Summary**

**§ 73.1 Purpose and scope.**

The purpose of this part is to establish the requirements and procedures
for the following:

\(a\) The allocation of sulfur dioxide emissions allowances;

\(b\) The tracking, holding, and transfer of allowances;

\(c\) The deduction of allowances for purposes of compliance and for
purposes of offsetting excess emissions pursuant to parts 72 and 77 of
this chapter;

\(d\) The sale of allowances through EPA-sponsored auctions and a direct
sale, including the independent power producers written guarantee
program; and

\(e\) The application for, and distribution of, allowances from the
Conservation and Renewable Energy Reserve.

\(f\) The application for, and distribution of, allowances for
desulfurization of fuel by small diesel refineries.

**§ 73.2 Applicability.**

The following parties shall be subject to the provisions of this part:

\(a\) Owners, operators, and designated representatives of affected
sources and affected units pursuant to § 72.6 of this chapter;

\(b\) Any new independent power producer as defined in section 416 of
the Act and § 72.2 of this chapter, except as provided in section
405(g)(6) of the Act;

\(c\) Any owner of an affected unit who may apply to receive allowances
under the Energy Conservation and Renewable Energy Reserve Program
established in accordance with section 404(f) of the Act;

\(d\) Any small diesel refinery as defined in § 72.2 of this chapter,
and

\(e\) Any other person, as defined in § 72.2 of this chapter, who
chooses to purchase, hold, or transfer allowances as provided in section
403(b) of the Act.

**Discussion:** Nevada Power Company is an affected source pursuant to §
72.6 of this chapter because it fits the definition of a utility unit;
therefore, this regulation shall apply.

**Subpart B -- Allowance Allocations**

Nevada Power Company is not listed on either the Phase I or Phase II
tables because it is a newer power plant; therefore, it will not have an
initial allocation per § 73.10.

**Subpart C -- Allowance Tracking System**

Nevada Power Company is considered a new unit. A complete certificate of
representation has been received and an account has been established for
this facility. Nevada Power Company shall follow all guidelines and
instructions presented in this subpart while maintaining its allowance
account.

**Subpart D -- Allowance Transfers**

When an allowance transfer is necessary, Nevada Power Company shall
follow all procedures in this subpart.

**Subpart E -- Auctions, Direct Sales, and Independent Power Producers
Written Guarantee**

This subpart outlines the auction process for allowance credits.

**Subpart F -- Energy Conservation and Renewable Energy Reserve**

There are no qualified conservation measures or renewable energy
generation processes at this facility; therefore, this subpart does not
apply.

**[40 CFR PART 75-CONTINUOUS EMISSION MONITORING]{.underline}**

**Subpart A -- General**

**40 CFR § 75.2 -- Applicability**

\(a\) Except as provided in paragraphs (b) and (c) of this section, the
provisions of this part apply to each affected unit subject to Acid Rain
emission limitations or reduction requirements for SO2 or NOX.

**Discussion:** Nevada Power Company is subject to the Acid Rain
emission limitations of 40 CFR Part 72; therefore, the facility is
subject to the monitoring requirements of this regulation.

Each combined cycle turbine unit has been equipped with both a NO~X~
CEMS and diluent oxygen monitors. Each turbine unit is also equipped
with a fuel flow monitor. Each turbine unit has a CO CEMS and a
CEMS-equivalent monitoring device to measure ammonia emissions. The data
from the CEMS are used to provide quarterly acid rain reports to both
EPA and DAQEM.

All required monitoring plans, Relative Accuracy Testing Audit (RATA)
testing protocols, and certification testing reports have been provided
to EPA and DAQEM. Initial CEMS certification testing was completed on
May 4, 2004. The CEMS Quality Assurance Plan was submitted to DAQEM on
February 12, 2003 and approved on August 11, 2003.

[]{#__RefHeading___Toc98123059 .anchor}

# V. COMPLIANCE

## []{.mark}

## A. Compliance Certification

19.3.3.9 Requirements for compliance certification:

(a) Regardless of the date of issuance of this Part 70 OP, the schedule
    for the submittal of reports to the DAQEM Compliance Reporting
    Supervisor shall be as follows:

+------+--------------+--------+--------------------------------------+
| **Q  | **Applicable | **Due  | **Required Contents**                |
| uart | Period**     | Date** |                                      |
| er** |              |        |                                      |
+------+--------------+--------+--------------------------------------+
| 1    | January,     | April  | Quarterly Report for 1^st^ Calendar  |
|      | February,    | 30     | Quarter                              |
|      |              |        |                                      |
|      | March        | each   |                                      |
|      |              | year   |                                      |
+------+--------------+--------+--------------------------------------+
| 2    | April, May,  | July   | Quarterly Report for 2^nd^ Calendar  |
|      |              | 30     | Quarter                              |
|      | June         |        |                                      |
|      |              | each   |                                      |
|      |              | year   |                                      |
+------+--------------+--------+--------------------------------------+
| 3    | July,        | O      | Quarterly Report for 3^rd^ Calendar  |
|      | August,      | ctober | Quarter                              |
|      |              | 30     |                                      |
|      | September    |        |                                      |
|      |              | each   |                                      |
|      |              | year   |                                      |
+------+--------------+--------+--------------------------------------+
| 4    | October,     | J      | Quarterly Report for 4^th^ Calendar  |
|      |              | anuary | Quarter, any additional annual       |
|      | November,    | 30     | records required, and                |
|      |              |        |                                      |
|      | December     | each   | Annual Certification of Compliance   |
|      |              | year   |                                      |
+------+--------------+--------+--------------------------------------+

\(b\) A statement of methods used for determining compliance, including
a description of monitoring, recordkeeping, and reporting requirements
and test methods.

\(c\) A schedule for submission of compliance certifications during the
permit term.

\(d\) A statement indicating the source\'s compliance status with any
applicable enhanced monitoring and compliance certification requirements
of the Act.

## B. Summary of Monitoring for Compliance

+-----+------+------+-----------+-----------+-------------------------+
| **E | **P  | **M  | **A       | **Requi   | **Compliance            |
| mis | roce | onit | pplicable | rements** | Monitoring**            |
| sio | ss** | ored | S         |           |                         |
| n** |      | Poll | ubsection |           |                         |
|     | **D  | utan | Title**   |           |                         |
| **U | escr | ts** |           |           |                         |
| nit | ipti |      |           |           |                         |
| \   | on** |      |           |           |                         |
| #** |      |      |           |           |                         |
+=====+======+======+===========+===========+=========================+
| A   | Co   | CO,  | AQR       | Annual    | CEMS for NO~X~ and CO.  |
| 01/ | mbus | NO   | Section   | and       |                         |
| A02 | tion | ~X~, | 12,       | s         | Stack testing by EPA    |
|     | turb | SO   | Section   | hort-term | Methods as approved by  |
| A   | ines | ~2~, | 19,       | emission  | DAQEM and EPA in        |
| 03/ | u    | PM~  | Section   | limits.   | current ATC/OP.         |
| A04 | nits | 10~, | 55        |           |                         |
|     |      | VOC, |           |           | Compliance for HAPs and |
|     |      | H    | 40 CFR    |           | non-CEMS monitored      |
|     |      | APs, | Subpart   |           | emissions shall be      |
|     |      | N    | GG        |           | based on fuel           |
|     |      | H~3~ |           |           | consumption and         |
|     |      |      | 40 CFR    |           | emission factors.       |
|     |      |      | Subpart   |           |                         |
|     |      |      | Da        |           | PEMS for NH~3~          |
|     |      |      |           |           |                         |
|     |      |      |           |           | Recording is required   |
|     |      |      |           |           | for compliance          |
|     |      |      |           |           | demonstration.          |
+-----+------+------+-----------+-----------+-------------------------+
| A   | Co   | Opa  | 40 CFR    | Opacity = | EPA Method 9 performed  |
| 01/ | mbus | city | Subpart   | 0%,       | every two years or      |
| A02 | tion |      | GG        | except    | 10,000 hours of         |
|     | turb |      |           | for 3     | operation.              |
| A   | ines |      | AQR       | min. out  |                         |
| 03/ | u    |      | Section   | of every  |                         |
| A04 | nits |      | 26        | 60 min.   |                         |
|     |      |      |           | period    |                         |
|     |      |      |           | when      |                         |
|     |      |      |           | Opacity ≤ |                         |
|     |      |      |           | 20%       |                         |
+-----+------+------+-----------+-----------+-------------------------+
| A05 | Di   | Opa  | AQR       | Opacity = | Per the request of the  |
|     | esel | city | Section   | 20%,      | Control Officer         |
|     | Fire |      | 26        | except    |                         |
|     | Pump |      |           | for 3     |                         |
|     |      |      |           | min. out  |                         |
|     |      |      |           | of every  |                         |
|     |      |      |           | 60 min.   |                         |
|     |      |      |           | period    |                         |
|     |      |      |           | when      |                         |
|     |      |      |           | Opacity ≤ |                         |
|     |      |      |           | 60%       |                         |
+-----+------+------+-----------+-----------+-------------------------+
| A06 | E    | Opa  | AQR       | Opacity = | Per the request of the  |
|     | merg | city | Section   | 20%,      | Control Officer         |
|     | ency |      | 26        | except    |                         |
|     | G    |      |           | for 3     |                         |
|     | ener |      |           | min. out  |                         |
|     | ator |      |           | of every  |                         |
|     |      |      |           | 60 min.   |                         |
|     |      |      |           | period    |                         |
|     |      |      |           | when      |                         |
|     |      |      |           | Opacity ≤ |                         |
|     |      |      |           | 60%       |                         |
+-----+------+------+-----------+-----------+-------------------------+
| A07 | Coo  | PM   | AQR       | Annual    | Recording is required   |
|     | ling | ~10~ | Section   | and       | for compliance          |
|     |      |      | 12        | s         | demonstration.          |
|     | T    |      |           | hort-term |                         |
|     | ower |      |           | emission  |                         |
|     |      |      |           | limits.   |                         |
+-----+------+------+-----------+-----------+-------------------------+

# VI. EMISSION REDUCTION CREDITS (OFFSETS)

At the time of this permitting action, the source has no federal offset
requirements.

# VII. ADMINISTRATIVE REQUIREMENTS

Section 19 requires that DAQEM identify the original authority for each
term or condition in the Part 70 Operating Permit. Such reference of
origin or citation is denoted by \[italic text in brackets\] after each
Part 70 Permit condition.

DAQEM proposes to issue the Part 70 Operating Permit conditions on the
following basis:

Legal:

On December 5, 2001 in Federal Register Volume 66, Number 234 FR30097
the EPA fully approved the Title V Operating Permit Program submitted
for the purpose of complying with the Title V requirements of the 1990
Clean Air Act Amendments and implementing Part 70 of Title 40 Code of
Federal Regulations.

Factual:

Nevada Power Company has supplied all the necessary information for
DAQEM to draft Part 70 Operating Permit conditions encompassing all
applicable requirements and corresponding compliance.

Conclusion:

DAQEM has determined that Nevada Power Company can continue to determine
compliance through the use of CEMS, performance testing, quarterly
reporting, daily recordkeeping, coupled with annual certifications of
compliance. DAQEM proceeds with the preliminary decision that a Part 70
Operating Permit should be issued as drafted to Nevada Power Company for
a period not to exceed five years.

**END OF TSD**