The EPA Regional Administrator, Jared Blumenfeld, signed the following proposed rule on 04/02/2012, and EPA

is submitting it for publication in the Federal Register (FR). While we have taken steps to ensure the accuracy of

this Internet version of the rule, it is not the official version of the rule for purposes of public comment. Please refer

to the official version in a forthcoming FR publication, which will appear on the Government Printing Office's

FDsys website (http://fdsys.gpo.gov/fdsys/search/home.action) and on Regulations.gov

(http://www.regulations.gov) in Docket No. EPA-R09-OAR-2011-0130. Once the official version of this document

is published in the FR, this version will be removed from the Internet and replaced with a link to the official version.

 Billing Code: 6560-50-P

ENVIRONMENTAL PROTECTION AGENCY

40 CFR Part 51

[EPA-R09-OAR-2011-0130, FRL- ]

Approval and Promulgation of Air Quality Implementation Plans; 

State of Nevada; Regional Haze State and Federal Implementation 

Plans; BART Determination for Reid Gardner Generating Station

AGENCY: Environmental Protection Agency (EPA)

ACTION: Proposed rule.

SUMMARY: EPA is proposing to partially approve and partially 

disapprove the remaining portion of a revision to the Nevada 

State Implementation Plan (SIP) to implement the regional haze 

program for the first planning period through July 31, 2018. 

This Notice proposes to approve the chapter of Nevada‟s Regional 

Haze SIP that requires Best Available Retrofit Technology (BART) 

for emissions limits of oxides of nitrogen (NOx) from Units 1 

and 2 at the Reid Gardner Generating Station (RGGS). We are 

proposing to disapprove the NOx emissions limit for Unit 3. We 

are also proposing to disapprove the provision of the RGGS BART 

determination that sets a 12-month rolling average for Units 1 

through 3. This Notice proposes to promulgate a Federal 

Implementation Plan (FIP) that establishes certain requirements 

for which the State, in a letter dated March 22, 2012, has 

agreed to submit a SIP revision. The FIP sets an emissions 
2

limit of 0.20 lbs/MMBtu (pounds per million British thermal 

units) for Unit 3 as BART and requires the determination of 

emissions from Units 1 through 3 based on a 30-day rolling 

average (averaged across all three units). In a prior action, 

EPA approved Nevada‟s Regional Haze SIP except for its BART 

determination for NOx for RGGS Units 1 through 3. 

DATES: Comments: Written comments must be received at the 

address below on or before [insert date 30 days from the date of 

publication in the Federal Register] 

Public Hearing: We will hold a public hearing in early May 

at a location near the Facility. We will post information on 

the specifics on our website at 

http://www.epa.gov/region9/air/actions/nv.html#haze and by 

publishing a notice in a general circulation newspaper at least 

15 days before the date of the hearing.

ADDRESSES: Submit your comments, identified by Docket ID No. 

EPA-R09-OAR-2011-0130 by one of the following methods:

1. Federal Rulemaking portal: http://www.regulations.gov. Follow 

the on-line instructions for submitting comments.

2. E-mail: Webb.Thomas@epa.gov

3. Fax: 415-947-3579 (Attention: Thomas Webb)
3

4. Mail: Thomas Webb, EPA Region 9, Planning Office, Air 

Division, 75 Hawthorne Street, San Francisco, California 94105.

5. Hand Delivery or Courier: Such deliveries are only accepted 

Monday through Friday, 8:30 AM – 4:30 PM, excluding federal 

holidays. Special arrangements should be made for deliveries of 

boxed information.

Instructions: Direct your comments to Docket ID No. EPA-R09-

OAR-2011-0130. Our policy is that EPA will include all comments 

received in the public docket without change. EPA may make 

comments available online at http://www.regulations.gov, 

including any personal information provided, unless the comment 

includes information claimed to be Confidential Business 

Information (CBI) or other information whose disclosure is 

restricted by statute. Do not submit information that you 

consider to be CBI or otherwise protected through 

http://www.regulations.gov or e-mail. The 

http://www.regulations.gov web site is an “anonymous access” 

system, which means EPA will not know your identity or contact 

information unless you provide it in the body of your comment. 

If you send an e-mail comment directly to EPA, without going 

through http://www.regulations.gov, EPA will include your e-mail 

address as part of the comment that is placed in the public 

docket and made available on the internet. If you submit an 

electronic comment, EPA recommends that you include your name 
4

and other contact information in the body of your comment and 

with any disk or CD-ROM you submit. If EPA cannot read your 

comment due to technical difficulties and cannot contact you for 

clarification, EPA may not be able to consider your comment. 

Electronic files should avoid the use of special characters, any 

form of encryption, and be free of any defects or viruses. For 

additional information about EPA's public docket visit the EPA 

Docket Center homepage at 

http://www.epa.gov/epahome/dockets.htm.

Docket: All documents in the docket are listed in the 

http://www.regulations.gov index. Although it is listed in the 

index, some information is not publicly available (e.g., CBI or 

other information whose disclosure is restricted by statute). 

Certain other material, such as copyrighted material, voluminous 

records or large maps, will be publicly available only in hard 

copy form. Publicly available docket materials are available 

either electronically at http://www.regulations.gov or in hard 

copy at the Planning Office of the Air Division, Air-2, EPA 

Region 9, 75 Hawthorne Street, San Francisco, CA 94105. EPA 

requests you contact the individual listed in the FOR FURTHER 

INFORMATION CONTACT section to view the hard copy material of 

the docket. You may view the hard copy material of the docket 

Monday through Friday, 9:00 – 5:30 PST, excluding federal 

holidays. 
5

FOR FURTHER INFORMATION CONTACT: Thomas Webb, U.S. EPA, Region 

9, Planning Office, Air Division, Air-2, 75 Hawthorne Street, 

San Francisco, CA 94105. Thomas Webb can be reached at 

telephone number (415) 947-4139 and via electronic mail at

webb.thomas@epa.gov.

Definitions

For the purpose of this document, we are giving meaning to 

certain words or initials as follows:

(1) The initials BART mean or refer to Best Available Retrofit 

Technology

(2) The initials CAA mean or refer to Clean Air Act

(3) The initials CCM mean or refer to EPA's Control Cost Manual

(4) The words or initials EPA, we, us or our mean or refer to 

the United States Environmental Protection Agency

(5) The initials GCNP mean or refer to Grand Canyon National 

Park

(6) The initials IMPROVE mean or refer to Interagency 

Monitoring of Protected Visual Environments 

(7) The word Jarbidge means or refers to the Jarbidge 

Wilderness Area

(8) The initials LNB mean or refer to low NOx burners
6

(9) The initials LTS mean or refer to Long-Term Strategy

(10) The initials NDEP mean or refer to Nevada Division of 

Environmental Protection

(11) The words Nevada and State mean or refer to the State of 

Nevada

(12) The initials NOx mean or refer to nitrogen oxides

(13) The initials OFA mean or refer to overfire air

(14) The initials RGGS means or refers to Reid Gardner 

Generating Station Units 1 through 3

(15) The initials RHR mean or refer to Regional Haze Rule

(16) The initials ROFA mean or refer to rotating overfire air

(17) The word Rotamix means or refers to a technology that 

combines a conventional SNCR system with a proprietary air and 

reagent injection system

(18) The initials RPG mean or refer to Reasonable Progress Goal

(19) The initials SCR mean or refer to selective catalytic 

reduction

(20) The initials SIP mean or refer to State Implementation 

Plan

(21) The initials FIP mean or refer to Federal Implementation 

Plan

(22) The initials SNCR mean or refer to selective non-catalytic 

reduction
7

(23) The initials TSD mean or refer to Technical Support 

Document

Table of Contents

I. Background 

II. State Submittals and EPA‟s Prior Action

III. Overview of Proposed Action

IV. Requirements for Regional Haze SIPs

A. Regional Haze Rule

B. Best Available Retrofit Technology

C. Roles of Agencies in Addressing Regional Haze

D. Lawsuits

V. EPA‟s Analysis of Nevada‟s RH SIP

A. Affected Class I Areas 

B. Identification of Sources Subject to BART

C. Evaluation of Nevada‟s NOx BART Determination for Reid 

Gardner Generating Station

1. Costs of Compliance 

2. Degree of Visibility Improvement 

3. Existing Pollution Control Technology

4. Remaining Useful Life of the Source

5. Energy and Non-air Quality Impacts
8

VI. Federal Implementation Plan to Address NOx BART for Reid 

Gardner

A. Unit 1 through 3 Averaging Period

B. Unit 3 Emission Limit

C. Control Technology Basis

VII. EPA‟s Proposed Action

VIII. Statutory and Executive Order Reviews

I. Background

The CAA requires each state to develop plans, referred to as 

SIPs, to meet various air quality requirements. A state must 

submit its SIPs and SIP revisions to us for approval. Once 

approved, a SIP is enforceable by EPA and citizens under the 

CAA, and is, therefore, federally enforceable. If a state fails 

to make a required SIP submittal or if we find that a state‟s 

required submittal is incomplete or unapprovable, then we must 

promulgate a FIP to fill this regulatory gap. CAA section 

110(c)(1). 40 U.S.C. 7410(c).

This proposed action is intended to fulfill the requirement 

that states adopt and EPA approve SIPs that address regional 

haze. In 1990, Congress added section 169B to the CAA to 

address regional haze issues, and we promulgated regulations 

addressing regional haze in 1999. 64 FR 35714 (July 1, 1999), 

codified at 40 CFR part 51, subpart P. For a more detailed 
9

discussion please see our prior proposed action at 76 FR 36450 

(June 22, 2011).

II. State Submittals and EPA’s Prior Action

The Nevada Division of Environmental Protection (NDEP)

adopted and transmitted its “Nevada Regional Haze State 

Implementation Plan” (Nevada RH SIP) to EPA Region 9 with a 

letter dated November 18, 2009. The Nevada RH SIP was complete 

by operation of law on May 18, 2010. Nevada provided public 

notice and held a public hearing on the proposed Best Available 

Retrofit Technology (BART) controls for four stationary sources, 

including RGGS, on April 23, 2009. The State submitted to EPA 

additional documentation of public process and adoption of a 

more stringent emission limit for one of the BART sources on 

February 18, 2010. Revised Nevada Division of Environmental 

Protection BART Determination Review of NV Energy‟s Reid Gardner 

Generation Station Units 1, 2 and 3, Revised October 22, 2009 

(hereinafter “RGGS BART Determination”). Nevada included in its 

SIP submittal NDEP‟s responses to written comments from EPA 

Region 9, the National Park Service, and a consortium of 

conservation organizations. NDEP responded to comments on its 

RGGS BART Determination for NOx in two sections of its 

documents.1 

 

1 See Appendix C (starting at C-8) and D (starting at D-141) of the NV 

Regional Haze SIP, available as attachments to EPA-R09-OAR-2011-0130-0003.
10

On June 22, 2011, EPA proposed to approve the entire Nevada 

Regional Haze SIP submittal, including the RGGS BART 

Determination. 76 FR 36450 (June 22, 2011). EPA received adverse 

comments on the proposed approval, including specific comments 

on NDEP‟s modeling and cost analysis of the RGGS BART 

Determination for NOx. See Modeling for the Reid Gardner 

Generating Station: Visibility Impacts in Class I Areas, 

Prepared by H. Andrew Gray, Ph.D., August 2011 and Review of 

EPA‟s Proposed Approval of a Revision to the State of Nevada‟s 

State Implementation Plan to Implement the Regional Haze 

Program, Comments on Determination of Best Available Retrofit 

Technology, August 22, 2011, prepared by Petra Pless, D. Env. 

and Bill Powers, P.E.2 (“Pless Powers Report”).

On December 13, 2011, EPA signed its final approval of the 

Nevada RH SIP submittal that was published in the Federal 

Register on March 26, 2012. 77 FR 17334 (March 26, 2012). In our 

final approval, we delayed taking any action on the Nevada‟s 

RGGS BART Determination for NOx.3 EPA indicated that we needed 

additional time to consider the substantial comments submitted 

on the RGGS BART Determination for NOx. 

On December 22, 2011, we sent a letter via email to NDEP 

requesting clarification on several issues related to the 

 

2 Both reports can be found as attachments to EPA-R09-OAR-2011-0130-0062, with 

supporting information located in -0063.

3 77 FR 17334
11

comments on the RGGS BART Determination for NOx.4 NDEP responded 

on February 6 and February 14, 2012 by providing us with costrelated information. These cost estimates consisted of updates 

to specific line items in order to reflect September 2011 

material costs, but did not include any supporting information 

such as detailed equipment lists, vendor quotes, or the design 

basis for line item costs. 

EPA requested further information from NDEP on March 14, 

2012 regarding the emissions limit that NDEP had proposed as 

BART for Unit 3.5 Comments submitted on our June 22, 2011, 

proposed approval indicated that the actual average emission 

rate that RGGS reported for Unit 3 was significantly lower than 

NDEP‟s BART emissions limit for NOx of 0.28 lb/MMBtu. Pless 

Powers at 48. EPA also requested information regarding NDEP‟s 

basis for allowing a 12-month rolling average for NOx for Units 

1 – 3, which was also raised as an issue in the comments. Pless 

Powers at 52. 

In response, NDEP informed EPA on March 22, 2012 that it 

had conducted further analysis resulting in NDEP‟s conclusion to 

lower the BART emissions limit for Unit 3 BART for NOx to 0.20 

lb/MMBtu.6 NDEP also informed EPA that its further analysis 

 

4 Email dated December 22, 2011, from Colleen McKaughan (EPA) to Mike Elges 

(NDEP) and others. 

5 Email dated March 14, 2012, from Colleen McKaughan (EPA) to Mike Elges 

(NDEP).

6 Letter dated March 22, 2012 from Mike Elges (NDEP) to Deborah Jordan (EPA).
12

supported determining the NOx BART limit for all RGGS Units 

based on a 30-day rolling average rather than the 12-month 

rolling average contained in the adopted rules and submitted 

SIP, provided that compliance is determined based on a threeunit average. Finally, NDEP indicated that it had evaluated 

requiring Selective Non-Catalytic Reduction (SNCR) with LNB and 

OFA rather than ROFA with Rotamix as BART. NDEP stated that 

Nevada Energy had installed ROFA on Unit 4 but that it has not 

operated as expected. NDEP anticipated SNCR with LNB and OFA 

would produce more reliable performance.

The Nevada RH SIP included an evaluation of SNCR finding 

that it would result in a higher emissions limit for each unit 

than ROFA with Rotamix.7 NDEP‟s recent re-evaluation has 

concluded that SNCR with LNB and OFA would result in a NOx BART 

emissions limit of 0.20 lb/MMBtu for Units 1 through 3. NDEP 

indicates that it will submit a SIP revision by September 2012 

that evaluates the substitution of SNCR with LNB and OFA for 

ROFA with Rotamix, lowers the NOx BART limit for RGGS Unit 3, 

and requires a NOx emissions limit of 0.20 lb/MMBtu on a 30-day 

rolling average (averaged across all three units).8

III. Overview of Proposed Action

 

7 As indicated by controlled emission rates summarized in Table 1, NDEP Reid 

Gardner BART Determination, October 22, 2009. Available as Docket Item No. 

EPA-R09-OAR-2011-0130-0005.

8 Letter dated March 22, 2012, from Mike Elges (NDEP) to Deborah Jordan (EPA).
13

Today‟s proposal addresses the RGGS BART Determination for 

NOx, and if finalized, will complete our action on the Nevada 

Regional Haze SIP submitted on November 18, 2009. In its BART 

determination of RGGS, NDEP considered several control 

technologies, including Selective Catalytic Reduction (SCR), 

SNCR and ROFA with Rotamix. NDEP concluded that SCR would result 

in a very small incremental improvement of visibility over other 

technologies, which did not justify the incremental cost of 

installing and operating SCR. The results of our own analysis 

of the incremental visibility improvement and cost for SCR 

differ from NDEP‟s analysis in certain respects, but support 

NDEP‟s decision to establish a NOx BART emission limit that 

could be achieved with ROFA and Rotamix (or SNCR) rather than 

requiring an emission limit consistent with SCR technology. This 

proposal and our TSD provide additional information concerning 

our approval of NDEP‟s determination that SCR is not required as 

BART for RGGS. We considered the comments that we received on 

our June 22, 2011, proposed approval. We also conducted an 

independent modeling analysis to evaluate the incremental 

visibility improvement attributable to the NOx emission rates 

indicated in the RH SIP. Our analysis examined the visibility 

improvement that would be expected by requiring RGGS to meet a 

NOx emission limit of 0.06 lbs/MMbtu based on installation and 

operation of SCR. Our proposed approval is based in large part 
14

on this modeling analysis, discussed in detail below and in the 

TSD, showing that SCR controls at RGGS would not result in 

enough incremental visibility improvement at a single Class I 

area to justify the incremental cost of the technology.9

Therefore, we are proposing to approve NDEP‟s 

determination that NOx BART for Units 1 and 2 is a limit of 0.20 

lbs/MMBtu, which can be achieved with ROFA with Rotamix, or with 

SNCR with LNB and OFA. We are proposing to disapprove NDEP‟s NOx 

BART determination for RGGS Unit 3 and the SIP‟s provision to 

measure NOx emissions from Units 1 through 3 on a 12-month 

rolling average. Because we are proposing to disapprove these 

provisions of the SIP, we are concurrently proposing a FIP. Our 

FIP proposes promulgating a NOx BART emissions limit for RGGS 

Unit 3 of 0.20 lbs/MMbtu. We are also proposing a FIP provision 

requiring that NOx emissions for RGGS Units 1 through 3 are 

measured on a rolling 30-day average (across all three units). 

Our justification for our proposed disapproval and proposed FIP 

provisions is discussed in detail in our Technical Support 

Document (TSD) in the docket for this Notice.

IV. Requirements for Regional Haze SIPs

A. Regional Haze Rule

 

9 In NDEP/Nevada Energy‟s analysis, and in our analysis, the highest impacted 

Class I area is Grand Canyon National Park.
15

Regional haze SIPs must establish a long-term strategy that 

ensures reasonable progress toward achieving natural visibility 

conditions in each Class I area affected by the state‟s 

emissions. For a further discussion of this topic, please see 

our Notice of Proposed Rulemaking. 76 FR 36450 (June 22, 2011).

B. Best Available Retrofit Technology

Section 169A of the CAA directs states to evaluate the use

of retrofit controls at certain larger, often uncontrolled,

older stationary sources in order to address visibility impacts

from these sources. Specifically, section 169A(b)(2)(A) of the

CAA requires states to revise their SIPs to contain such

measures as may be necessary to make reasonable progress towards

the natural visibility goal, including a requirement that

certain categories of existing major stationary sources10 built

between 1962 and 1977 procure, install, and operate the “Best

Available Retrofit Technology” as determined by the state. 

Under the RHR, states are directed to conduct BART

determinations for such “BART-eligible” sources that may be

anticipated to cause or contribute to any visibility impairment

in a Class I area.

C. Roles of Agencies in Addressing Regional Haze 

 

10 The set of “major stationary sources” potentially subject to BART is listed 

in CAA section 169A(g)(7).
16

Successful implementation of the regional haze program will 

require long-term coordination among states, tribal governments 

and various federal agencies. EPA published on July 6, 2005, the 

Guidelines for BART Determinations under the Regional Haze Rule 

at Appendix Y to 40 CFR Part 51 (hereinafter referred to as the 

“BART Guidelines”) to assist states in determining which of 

their sources should be subject to the BART requirements and in 

determining appropriate emission limits for each applicable 

source. In making a BART determination for a fossil fuel-fired 

electric generating plant with a total generating capacity in 

excess of 750 megawatts, a state must use the approach set forth 

in the BART Guidelines. In contrast, however, our BART 

Guidelines encourage, but do not require, States to follow the 

BART Guidelines in making BART determinations for other types of

sources, including fossil fuel-fired electric generating plants 

with a total generating capacity that is less than 750 

megawatts. 70 FR 39104, 39108 (July 6, 2005)(“The better 

reading of the Act indicates that Congress intended the 

guidelines to be mandatory only with respect to 750 megawatt 

power plants.”) The CAA, therefore, allows States to exercise 

broader discretion in applying the BART guidelines to power 

plants that are smaller than 750 megawatts, such as RGGS. Id.

In their SIPs, states must document their BART control 

determination analyses. In making BART determinations, section 
17

169A(g)(2) of the CAA requires that states consider the 

following factors: (1) the costs of compliance; (2) the energy 

and non-air quality environmental impacts of compliance; (3) any 

existing pollution control technology in use at the source; (4) 

the remaining useful life of the source; and, (5) the degree of 

improvement in visibility which may reasonably be anticipated to 

result from the use of such technology. States are free to 

determine the weight and significance assigned to each factor, 

and as discussed above, generally have greater latitude in this 

determination for power plants that are smaller than 750 

megawatts.

A regional haze SIP must include source-specific BART

emission limits and compliance schedules for each source subject

to BART. Once a state has made its BART determination, the BART

controls must be installed and in operation as expeditiously as

practicable, but no later than five years after the date EPA

approves the regional haze SIP. CAA section 169(g)(4). 40 CFR

51.308(e)(1)(iv). In addition to what is required by the RHR,

general SIP requirements mandate that the SIP must also include

all regulatory requirements related to monitoring, recordkeeping 

and reporting for the BART controls on the source.

D. Lawsuits 

In two separate lawsuits, environmental groups sued EPA for 

our failure to take timely action with respect to the regional 
18

haze requirements of the CAA and our regulations. In particular, 

the lawsuits alleged that we had failed to promulgate FIPs for 

these requirements within the two-year period allowed by CAA 

section 110(c) or, in the alternative, fully approve SIPs 

addressing these requirements. EPA entered into a Consent 

Decree agreeing to sign a Federal Register Notice taking action 

on the Nevada RH SIP by December 13, 2011. The litigants agreed 

to extend our time for taking action on the RGGS NOx BART 

determination portion of the Nevada SIP given the extensive 

comments we received on our June 22, 2011, proposed approval. 

Our proposed action today meets our agreement with the 

litigants.

V. EPA’s Analysis of Nevada’s RH SIP

A. Affected Class I Areas 

 There are four Class I areas within a 300 kilometer (km) 

radius of RGGS: Grand Canyon National Park, Bryce Canyon 

National Park, Zion National Park and Sycamore Canyon 

Wilderness. Joshua Tree National Monument is just on the border 

of the 300 km radius of RGGS. Of these, GCNP is the nearest 

area to RGGS, located at a distance of 85 km.

B. Identification of Sources Subject to BART

EPA‟s final approval of the Nevada RH SIP agreed with 

NDEP‟s determination of its BART-eligible sources within the 
19

state, and its determination of which sources were subject to 

BART based on their contribution to visibility impairment. 

EPA‟s final approval included NDEP‟s BART determinations for the 

Tracy, Fort Churchill, and Mohave electrical generating 

stations.11 In our final approval of the Nevada RH SIP, we took 

no action on NDEP‟s NOx BART Determination for RGGS.

C. Evaluation of Nevada’s NOx BART Determination for Reid 

Gardner Generating Station

Background: Reid Gardner is a coal-fueled, steam-electric 

generating plant with four operating units producing a total of 

557 MW. Three of the units, built in 1965, 1968, and 1976 are 

BART-eligible, and were determined by NDEP to be subject to 

BART. Each of these units produces about 100 MW with steam 

boilers that drive turbine-generators. At present, the units 

are equipped with LNB and over-fire air (OFA) systems, 

mechanical collectors for particulate control, wet scrubbers

that use soda ash for sulfur dioxide (SO2) removal, as well as 

recently installed baghouses. NDEP‟s review of Nevada Energy‟s 

BART report for RGGS resulted in NDEP agreeing only with the 

control technologies proposed as BART for SO2 and PM10.

12 

NOx BART Determination: NDEP performed a five-factor 

analysis for the BART-eligible units at RGGS that included 

 

11 77 FR 17334

12 EPA approved that portion of NDEP’s BART determination for RGGS on December 13, 2011.
20

several feasible technologies including SCR, SNCR, and ROFA with 

Rotamix, among other control technologies. NDEP eliminated SCRbased options and determined that BART controls for NOx are 

rotating opposed fire air (ROFA) with Rotamix for Units 1 

through 3. For this control technology, NDEP determined 

emission limits, based on a rolling 12-month average, of 0.20 

lb/MMBtu for Units 1 and 2, and 0.28 lb/MMBtu for Unit 3. In 

its five factor analysis, NDEP eliminated SCR because it gave 

significant weight to the incremental cost of compliance. NDEP 

also cited the relatively low visibility improvement at GCNP 

that would result from SCR over ROFA with Rotamix.

EPA has carefully reviewed NDEP‟s BART analysis, focusing 

primarily on the incremental cost of compliance and incremental 

degree of improvement of visibility between SCR and ROFA with 

Rotamix. After receiving extensive comments in August 2011, we 

performed a significant amount of additional analysis for these 

two factors, including revisions to control cost calculations 

and new CALPUFF visibility modeling.

1. Costs of compliance

NDEP‟s analysis: NDEP evaluated the costs of compliance for 

each feasible NOx control option by analyzing the average and 

incremental cost effectiveness of each control technology. 

Average cost effectiveness ($/ton) is based on the total 

annualized cost ($) of a control option divided by the total 
21

amount of NOx removed (tons) by that control option. 

Incremental cost effectiveness is calculated when considering 

one control technology in relation to another, and examines the 

differing costs and the differing NOx removal ability of the two 

control options. 

When moving from a less stringent to a more stringent NOx 

control technology, the more stringent technology will result in 

greater amounts of NOx removal, but will also typically be more 

expensive. Incremental cost ($/ton) is calculated by dividing 

the difference in annualized costs ($) of the two technologies 

by the difference in NOx removal (ton) of the two technologies. 

Incremental costs are typically calculated “in order”, by 

comparing one control technology with the less stringent 

technology immediately preceding it. The control cost data that 

NDEP included in the RH SIP and relied upon in making its NOx 

BART determination is summarized in Table 1 below.

Table 1. Summary of NDEP NOx BART Determination Results for RGGS 

Unit 1 through 3 (as included in the RH SIP)

Control 

Option

Control 

Efficiency1

Emission 

Rate1

Emission 

Reduction1

Annualized 

Costs1

Average Cost

Effectiveness1

Incremental 

Cost 

Effectiveness1

(%)

(lb/ 

MMBtu) (ton/yr) ($MM) ($/ton) ($/ton)

Reid Gardner Unit 1

LNB + OFA 

(enhanced) 21.3% 0.36 483 $0.55 $1,143 $1,143

LNB + OFA + 

SNCR 40.9% 0.27 927 $1.13 $1,222 $1,308

ROFA + 

Rotamix 57.7% 0.2 1308 $1.45 $1,109 $833

SCR + LNB + 

OFA 81.6% 0.085 1850 $4.75 $2,566 $6,085

SCR + ROFA3 81.6% 0.085 1850 $5.39 $2,916 $7,280

Reid Gardner Unit 2
22

LNB + OFA 

(enhanced) 23.7% 0.355 580 $0.55 $952 $952

LNB + OFA + 

SNCR 42.7% 0.267 1044 $1.16 $1,106 $1,299

ROFA + 

Rotamix 59.0% 0.19 1443 $1.50 $1,038 $860

SCR + LNB + 

OFA 82.2% 0.083 2010 $4.80 $2,386 $5,813

SCR + ROFA3 82.2% 0.083 2010 $5.47 $2,721 $7,001

Reid Gardner Unit 3

LNB + OFA 

(enhanced) 6.5% 0.42 147 $0.55 $3,742 $3,742

LNB + OFA + 

SNCR 29.9% 0.316 678 $1.08 $1,596 $1,000

ROFA + 

Rotamix 38.0% 0.278 869 $1.38 $1,588 $1,560

SCR + LNB + 

OFA 78.2% 0.098 1774 $4.72 $2,660 $3,688

SCR + ROFA2 78.2% 0.098 1774 $5.40 $3,045 $4,444

1 As summarized in Table 1, NDEP Reid Gardner BART Determination, October 22, 2009. Available 

as Docket Item No. EPA-R09-OAR-2011-0130-0005.

2 Incremental cost effectiveness based on ROFA + Rotamix as previous control technology 

The annualized costs listed in Table 1 are based on total 

capital installation costs and certain annual operating costs 

submitted to NDEP by Nevada Energy in its BART analysis. These 

costs were relied upon by NDEP and included in the SIP without 

modification. These cost calculations provided line item 

summaries of capital costs and annual operating costs, but did 

not provide further supporting information such as detailed 

equipment lists, vendor quotes, or the design basis for line 

item costs.

In its RH SIP, NDEP indicated that it based its NOx BART 

determination of ROFA with Rotamix rather than SCR primarily on 

the incremental costs of compliance. NDEP judged the costs of 

ROFA with Rotamix as cost effective based on an average cost 

effectiveness of approximately $1100-1600/ton, as seen in Table 

1. NDEP then eliminated more stringent control options, such as 
23

the SCR-based options, based on high incremental cost 

effectiveness. Specifically, NDEP stated that “the $/ton of NOx

removed increased significantly . . . without correspondingly 

significant improvements in visibility.”13 Per NDEP estimates, 

the incremental cost effectiveness of SCR with LNB and OFA is 

approximately $3,600-6,100/ton. NDEP determined that this 

additional incremental cost per ton for SCR technologies did not 

appear cost effective compared to the incremental visibility 

improvement achieved by the SCR-based control options. 

EPA‟s analysis: In reviewing the Nevada RH SIP and public 

comments, we identified several aspects of NDEP‟s approach to 

this factor with which we disagreed, and for which we have 

performed additional analysis. We received several public 

comments that NDEP‟s cost calculations were overestimated and 

based on methodology inconsistent with EPA‟s Control Cost Manual

(CCM).

14 We agree that NDEP included inappropriate costs and our 

analysis excludes those costs that are not allowed by the CCM. 

Therefore, we have revised these cost calculations and adjusted 

the value of specific variables to conform to values allowed by 

the CCM. Aside from these items, other commenters alleged that 

aspects of NDEP‟s cost estimates were unjustified or 

 

13 Revised NDEP Reid Gardner BART Determination Review, page 6. Available as 

Docket Item No. EPA-R09-OAR-2011-0130-0005.

14 See comments from NPCA Consortium (EPA-R09-OAR-2011-0130-0062), National 

Park Service and U.S. Fish and Wildlife Service (EPA-R09-OAR-2011-0130-0054) 

and in expert report by Petra Pless/Bill Powers (attachment to EPA-R09-OAR2011-0130-0062).
24

overestimated, such as a failure to account for multiple unit 

discount and overestimated reagent costs.15 We agree that the 

record does not support the positions that NDEP has taken on 

these cost items. However, we did not account for these 

additional discrepancies in our revised cost estimate since 

disallowing those costs not in the CCM resulted in our finding 

that SCR is cost effective. The disallowed costs result in a 

decrease of 25-33 percent in the average and incremental cost 

effectiveness of the control technology options. Detailed cost 

calculations, in which we revised the original cost calculations

(as included in the RH SIP) and the updated cost calculations 

(as provided by NDEP on February 14, 2012) for each NOx control 

technology, are included in Appendix A of our TSD. Summarized in 

Table 2 below is a comparison of the updated NDEP cost 

calculations (as provided on February 14, 2012) and our revised 

cost calculations for the SCR with LNB and OFA control 

technology option.

Table 2. Cost Effectiveness Comparison – SCR with LNB and OFA

Unit No. Average Cost 

Effectiveness

($/ton)

Incremental Cost 

Effectiveness 

($/ton)

NDEP EPA 

Revised

NDEP EPA 

Revised

Unit 1 $2,827 $2,110 $6,370 $4,534 

Unit 2 $2,627 $1,967 $6,080 $4,330 

Unit 3 $2,932 $2,183 $3,856 $2,756 

 

15 These items were primarily noted in the expert report by Petra Pless/Bill 

Powers (attachment to EPA-R09-OAR-2011-0130-0062).
25

Based on our revised cost estimates, we do not consider these 

average and incremental cost effectiveness values for SCR with 

LNB and OFA as cost prohibitive. Our analysis of this factor 

indicates that costs of compliance (average and incremental) are 

not sufficiently large to warrant eliminating SCR from 

consideration. 

The incremental cost effectiveness values for Units 1 and 2 

are around $4,500/ton. Although EPA does not consider this 

incremental cost prohibitive, we note that the State has certain 

discretion in weighing this cost. Because RGGS is not a facility 

over 750 megawatts and therefore not subject to EPA‟s 

presumptive BART limits, the State may exercise its discretion 

more broadly in this particular determination. 

2. Degree of visibility improvement

NDEP‟s Analysis: As part of its BART analysis, Nevada 

Energy performed visibility modeling in order to evaluate the 

visibility improvement attributable to each of the NOx control 

technologies that it considered. Results of the visibility 

modeling performed by Nevada Energy in its submittal to NDEP are 

summarized in Table 3 below. 

Table 3. Summary of Nevada Energy Estimates of Visibility 

Benefit16

 

16 Visibility improvement listed here are for the Class I area with the 

highest impact, Grand Canyon National Park. They represent the change in the 

98th percentile impacts from three modeled years. The “total” is the simple 
26

Control Option

Visibility Improvement 

(from WRAP baseline)17

Visibility 

Improvement 

(Incremental, 

from Control)

RGGS1 RGGS2 RGGS3 Total Total 

(dv) (dv) (dv)

LNB + OFA (enhanced) 0.440 0.479 0.407 1.33 --

LNB + OFA + SNCR 0.521 0.560 0.485 1.57 0.24

ROFA + Rotamix 0.592 0.630 0.514 1.74 0.17

SCR + LNB + OFA 0.698 0.735 0.652 2.09 0.35

SCR + ROFA18 0.698 0.735 0.652 2.09 0.35

Based upon these results, the installation of SCR with LNB 

and OFA would result in an incremental visibility improvement at 

Grand Canyon National Park of 0.35 deciviews (dv). This 

visibility improvement is based upon the NOx emission rates 

estimated by Nevada Energy in their BART analysis for each 

control technology option, and is relative to visibility impacts 

based on emissions used by the Western Regional Air Partnership

(WRAP). In preparing the RH SIP, however, NDEP developed its 

own set of NOx emission estimates for the various control 

technology options. The differences between Nevada Energy‟s 

estimates and the emission estimates that form the basis of the 

Nevada RH SIP are summarized in Table 4 below. 

 

total of the impacts from the three individual units, which Nevada Energy 

modeled separately..

17 From Table 5-4 of NVE BART Analysis Reports, Reid_Gardner_1_10-03-08.pdf, 

Reid_Gardner_2_10-03-08.pdf, Reid_Gardner_3_10-03-08.pdf. Available in Docket 

Item No. EPA-R09-OAR-2011-0130-0007. The improvements here are relative to 

the “WRAP baseline”, impacts from emission levels used by the Western 

Regional Air Partnership and modeled by Nevada Energy. This is a different 

“baseline” than used for the cost estimates below.

18 Incremental visibility benefit of SCR + ROFA is based upon ROFA + Rotamix 

as previous control technology.
27

Table 4. Comparison of Nevada Energy and NDEP Control 

Technology Emission Estimates

Control Option Nevada Energy NDEP

Emission 

Factor1

Control 

Efficiency2

Emission 

Factor3

Control 

Efficiency3

(lb/MMBtu) (%) (lb/MMBtu) (%)

Reid Gardner Unit 1

Baseline (LNB + OFA) 0.38 -- 0.462 --

LNB + OFA (enhanced) 0.30 21.3% 0.360 21.3%

LNB + OFA + SNCR 0.23 40.9% 0.270 40.9%

ROFA + Rotamix 0.16 57.7% 0.200 57.7%

SCR + LNB + OFA 0.07 81.6% 0.085 81.6%

SCR + ROFA 0.07 81.6% 0.085 81.6%

Reid Gardner Unit 2

Baseline (LNB + OFA) 0.393 -- 0.466 --

LNB + OFA (enhanced) 0.30 23.7% 0.355 23.7%

LNB + OFA + SNCR 0.23 42.7% 0.267 42.7%

ROFA + Rotamix 0.16 59.0% 0.190 59.0%

SCR + LNB + OFA 0.07 82.2% 0.083 82.2%

SCR + ROFA 0.07 82.2% 0.083 82.2%

Reid Gardner Unit 3

Baseline (LNB + OFA) 0.32 -- 0.451 --

LNB + OFA (enhanced) 0.30 6.5% 0.420 6.5%

LNB + OFA + SNCR 0.23 29.9% 0.316 29.9%

ROFA + Rotamix 0.20 38.0% 0.278 38.0%

SCR + LNB + OFA 0.07 78.2% 0.098 78.2%

SCR + ROFA 0.07 78.2% 0.098 78.2%

1 From each respective unit's NVE BART Analysis, Table 3-1. Available in 

Docket Item No. EPA-R09-OAR-2011-0130-0007

2 From each respective unit's NVE BART Analysis, Table 3-2. Available in 

Docket Item No. EPA-R09-OAR-2011-0130-0007

3 As summarized in Table 1, NDEP Reid Gardner BART Determination, October 

22, 2009. Available as Docket Item No. EPA-R09-OAR-2011-0130-0005. Baseline 

emission factor is not explicitly calculated by NDEP. The factor listed in 

this table represents the listed annual emissions divided by “Base Heat 

Input”.

As seen in these tables, NDEP‟s estimates of controlled 

emission rates differ from Nevada Energy‟s estimates. These 

differences are a result of NDEP‟s use of a different emission 

baseline in its calculations than Nevada Energy, which is 
28

discussed below in our discussion of existing pollution control 

technology. Since NDEP elected to calculate controlled emission 

rates by retaining the respective percent reduction values for 

each control technology, rather than each control technology‟s 

emission rate (lb/MMBtu), the use of a higher baseline emission 

rate results in higher emission estimates for each control 

technology option. As a result, NDEP‟s estimated performance 

for each control technology is less stringent than Nevada 

Energy‟s estimates. NDEP, however, did not perform additional 

modeling to determine the visibility improvement attributable to 

its emission estimates, and continued to rely on the visibility 

modeling performed by Nevada Energy. 

As noted in the discussion of cost of compliance, part of 

NDEP‟s basis for rejecting control technology options more 

stringent that ROFA with Rotamix as BART was that the 

incremental costs of more stringent control options were not 

justified relative to their corresponding increases in 

visibility improvement. However, without updated visibility 

modeling that indicates the visibility improvement attributable 

to NDEP‟s emission estimates, we do not consider NDEP to have 

properly considered the appropriate magnitude of incremental 

visibility improvement in reaching its determination. As 

discussed below, we have performed our own visibility modeling 

to determine these visibility impacts. 
29

EPA‟s Analysis: In performing our own visibility modeling, 

the primary goal of our approach was to determine the visibility 

improvement associated with the NOx emission estimates relied 

upon in the RH SIP. In developing a modeling strategy, we 

decided that an approach that consisted of simply using Nevada 

Energy‟s modeling with model emission rates updated to reflect 

NDEP‟s estimates was not appropriate. As a result of changes to 

CALPUFF regulatory guidance that have occurred in the 

intervening time since Nevada Energy performed its visibility 

modeling, we elected to perform our visibility modeling in a 

manner that more closely adheres with current EPA regulatory 

guidance on CALPUFF modeling. Key elements of our modeling 

approach that differ from Nevada Energy‟s modeling include:

- CALPUFF system version: we performed our visibility modeling 

using version 5.8 of the CALPUFF model, and version 5.8 of the 

CALMET meteorological preprocessor, which are the current 

regulatory-approved versions. Nevada Energy‟s modeling used 

CALPUFF version 6.112, and CALMET version 6.211.

- Meteorological inputs: we used the meteorological inputs 

developed by the Western Regional Air Partnership, augmented 

with upper air data. Nevada Energy‟s modeling used some 

different inputs, and did not incorporate upper air data.

- SCR catalyst conversion efficiency: we performed our 

visibility modeling using an SCR catalyst SO2 to SO3 conversion 
30

efficiency of 0.5 percent for purposes of calculating sulfuric 

acid emissions. Nevada Energy‟s modeling relied upon 1 percent

conversion efficiency.

- Calculation of visibility impact: we calculated our 

visibility impacts using the revised IMPROVE equation (Method 8, 

mode 5)19 in addition to the original IMPROVE equation (Method 

6). Nevada Energy‟s modeling was performed before the 

availability of modeling guidance regarding the use of the 

revised IMPROVE equation and its incorporation into CALPUFF as

Method 8.

- Control technology performance: we performed our visibility 

modeling using the NOx baseline emission rate and NOx control 

technology emission rates listed under the “NDEP” column in 

Table 4, which had not previously been modeled. 

- In addition, we modeled another SCR control technology case 

corresponding to a NOx emission rate of 0.06 lb/MMBtu. As 

indicated in Table 4, both Nevada Energy and NDEP used control 

efficiency values in the range of 78 to 82 percent to estimate 

SCR performance. Typical SCR catalyst vendor guarantees can 

 

19 The IMPROVE equation translates modeled or monitored concentrations of 

pollutants like sulfate and nitrate into extinction, a measure of visibility. 

See: http://vista.cira.colostate.edu/improve/ Extinction, in turn, is used 

to calculate deciviews, the visibility impact metric used in the BART 

Guidelines. The various visibility “methods” in CALPUFF differ in how they 

account for background concentrations and adjustments for relative humidity. 

Method 8, mode 5 is the currently-recommended method. “Federal Land 

Managers‟ Air Quality Related Values Workgroup (FLAG) Phase I Report” 

(December 2000), U.S. Forest Service, National Park Service, U.S. Fish And 

Wildlife Service. See: 

http://www.nature.nps.gov/air/Pubs/pdf/flag/FlagFinal.pdf
31

indicate 90 percent NOx reduction.20 We have elected to model 

0.06 lb/MMBtu based on a selection of a mid-range control 

efficiency of 85 percent reduction from Nevada Energy‟s NOx 

emission baseline. 

A more detailed discussion of our visibility modeling, 

including full visibility results for all Class I areas located 

within 300 km of RGGS, is in our TSD and associated emission 

calculation spreadsheet. A summary of visibility results is 

presented in Table 5 below.

Table 5. Summary of Visibility Impacts

Control Option Visibility 

Impact1 (all 

three units)

Visibility Improvement

From Baseline Incremental, From 

Previous Option

(dv) (dv) (dv)

Baseline (LNB w/ OFA) 0.59 -- --

LNB w/ OFA (enhanced) 0.51 0.08 0.08

SNCR + LNB w/ OFA 0.37 0.21 0.13

ROFA w/ Rotamix 0.31 0.28 0.06

SCR w/ LNB + OFA 0.22 0.36 0.09

SCR w/ LNB + OFA2

(0.06 lb/MMBtu, each unit)

0.20 0.38 0.10

1 Visibility impact summarized here represents the three-year 98th percentile impact at the Class I area with the 

highest impact, Grand Canyon National Park All three units were modeled together. The CALPUFF model output 

was post-processed using CALPOST visibility Method 8, the revised IMPROVE equation, and using natural 

background concentrations for the best 20% of days. For full visibility results, including impacts at other Class I 

areas within 300 km and using other visibility methods, please see the TSD in today’s docket.

2

Incremental visibility improvement compared to ROFA with Rotamix.

As seen in these results, the total incremental visibility 

improvement resulting from the installation of SCR with LNB and 

 

20 We received public comments to this effect that included multiple vendor 

quotes. Available as attachments to Docket Items EPA-R09-OAR-2011-0130-0062 

and -0063.
32

OFA compared to ROFA with Rotamix is 0.09 dv. This occurred at 

Grand Canyon National Park, the Class I area with the highest 

impact. In addition, we note that even our additional scenario 

that models the SCR control option at a 0.06 lb/MMBtu level of 

performance results in an incremental visibility improvement of 

only 0.10 dv relative to ROFA with Rotamix. Based on this small 

quantity of incremental visibility improvement, we agree with 

NDEP‟s conclusion that the control options more stringent than 

ROFA with Rotamix (or SNCR with LNB and OFA achieving the same 

emission limit) are not justified.

3. Existing pollution control technology

NDEP‟s analysis: Nevada Energy prepared and submitted a 

BART analysis to NDEP that accounted for the presence of low-NOx 

burners by using baseline NOx emission factors corresponding to 

2004 actual emissions data.21 In preparing the RH SIP, NDEP 

developed a baseline NOx emission factor that was based upon 

past actual emission data over a 2001-07 time frame.22 This 

resulted in baseline NOx emission rates that are approximately 

15 percent higher than those presented in Nevada Energy‟s BART 

analysis.

EPA‟s analysis: While NDEP‟s use of a set of baseline 

emissions different from those presented in Nevada Energy‟s BART 

 

21 Baseline emission factors as listed in Table 2-2 of each unit’s respective Nevada Energy BART Analysis. 

Available as attachments to EPA-R09-OAR-2011-0130-0007.

22 Per NDEP’s Reid Gardner BART Determination Summary, NDEP used the average of the two consecutive years 

with highest annual emissions. Available as Docket Item No. EPA-R09-OAR-2011-0130-0005.
33

analysis does result in a higher baseline emission rate, NDEP‟s 

baseline emissions still reflect the use of low-NOx burners. We 

find that NDEP‟s approach to this factor is reasonable, and have 

not modified NDEP‟s NOx emission baseline in performing our own 

analysis. We do note that due to the emission calculation 

methodology NDEP used to calculate NOx control scenario 

emissions, increases to the NOx emission baseline will affect 

emission estimates for NOx control scenarios. These effects are 

discussed further in the analysis of degree of visibility 

impact.

4. Remaining useful life of the source

NDEP‟s analysis: In its BART analysis submittal to NDEP, 

Nevada Energy used a plant economic life of 20 years and 

performed control technology cost calculations based on control 

equipment lifetime equal to the plant economic life. In 

developing the RH SIP, NDEP relied upon these cost calculations 

without revision.

EPA‟s analysis: Use of a 20-year equipment life is 

consistent with assumptions made in EPA‟s Control Cost Manual 

for the equipment lifetime of certain NOx control technologies 

such as SCR and SNCR. Commenters alleged that without a firm 

shutdown date to ensure a plant lifetime of 20 years, a longer 

equipment life should be used in cost calculations. Use of a 

longer equipment life would result in lower annualized costs, 
34

thereby making control technologies more cost effective. As 

discussed further in the analysis of costs of compliance, we 

already consider certain control technology options more 

stringent than ROFA with Rotamix, such as SCR with LNB and OFA, 

to be cost effective. As a result, we decline to pursue an 

analysis examining whether use of a 20-year plant economic life 

is appropriate. 

5. Energy and non-air quality impacts

NDEP‟s Analysis: In its BART analysis submitted to NDEP, 

Nevada Energy identified certain energy impacts such as 

increased energy usage associated with ROFA as a result of 

induced draft fan installations. For SCR installations, 

increased energy usage is expected in order for existing fan 

systems to compensate for the additional pressure drop created 

by the SCR catalyst bed. Nevada Energy quantified these energy 

impacts as annual operating cost line items in cost 

calculations. 

Non-air quality impacts identified by Nevada Energy in its 

BART analysis include the potential for ammonia slip from SCR or 

SNCR to impact the salability and disposal of fly ash, as well 

as to create a visible stack plume. The potential for 

transportation and storage of ammonia to result in an accidental 

release was also identified as a potential non-air quality 

impact. Nevada Energy cited these as negative impacts in its 
35

consideration of SCR and SNCR control options. In preparing the 

RH SIP, NDEP did not further expand on these impacts in 

determining ROFA with Rotamix as BART for NOx. 

EPA‟s Analysis: Although we consider the energy impacts 

accounted for by Nevada Energy to be reasonable, we note that 

supporting calculations were not provided for the line item cost 

associated with these impacts in control cost calculations. At 

this time, we decline to provide our own estimate of these 

impacts. Regarding non-air quality impacts, while we 

acknowledge that the items described by Nevada Energy are indeed 

potential concerns for the control technologies considered, we 

note that neither Nevada Energy‟s analysis nor the RH SIP 

provide further information discussing the extent to which these 

are site-specific concerns for RGGS Units 1 through 3. As a 

result, we consider these non-air quality impacts as not

sufficiently significant at RGGS to warrant eliminating any of 

the control technology options.

VI. Federal Implementation Plan to Address NOx BART for Reid 

Gardner

Although our analysis supports NDEP‟s decision to not 

require control technology options more stringent than ROFA with 

Rotamix (or SNCR with LNB and OFA achieving the same emissions 

limit) as BART, completion of the BART process requires 

establishing enforceable emission limits that reflect the BART 
36

control technology requirements.23 As described in the sections 

below, we find certain elements of the emission limits 

established for RGGS in the RH SIP as either unsupported by the 

record or inconsistent with BART Guidelines. NDEP notified us 

in a letter dated March 22, 2012 that it intends to submit a RH 

SIP revision that will address these elements, which include 

establishing a NOx limit of 0.20 lb/MMBtu for Unit 3, and 

establishing NOx limits for each unit on a 30-day rolling 

average (averaged across all three units), rather than a 12-

month rolling average. In addition, NDEP has indicated that the 

RH SIP revision it intends to submit will revise the selected 

control technology from ROFA with Rotamix to SNCR with LNB and 

OFA. 

In order to meet the terms of our consent decree, it is 

necessary for EPA to propose action on Nevada‟s RH SIP at this 

time. As a result, we are proposing the promulgation of a FIP 

that will address the elements described below. We expect these 

elements to match the content of the revised RH SIP that Nevada 

has indicated it intends to submit. 

Based upon the March 22, 2012 letter sent by NDEP 

indicating its intent to submit a revised RH SIP, we do not 

expect to receive the revised RH SIP prior to our consent decree 

deadline for final action on this proposal. Although we will 

 

23 70 FR 39172
37

not receive the revised RH SIP prior to our final action, we do 

intend to act expeditiously on the revised RH SIP once it is 

submitted to EPA.

A. Unit 3 Emission Limit

We are proposing to promulgate a FIP to establish a NOx 

emission limit of 0.20 lb/MMBtu for Unit 3. In its RH SIP, NDEP 

proposed a NOx emission limit of 0.28 lb/MMBtu for Unit 3. This 

limit for Unit 3 (0.28 lb/MMBtu) was higher than the emission 

limit NDEP proposed for Units 1 or 2 (0.20 lb/MMBtu each). The 

higher emission limit appears to be partially attributable to 

the fact that the application of control technology to Unit 3 

was projected to result in less stringent levels of performance 

relative to Units 1 and 2. As shown in Table 4 of this notice, 

Nevada Energy‟s emission estimates indicate that application of 

ROFA with Rotamix achieves nearly 60 percent reduction from 

baseline on Units 1 and 2, but only a 38 percent reduction from 

baseline on Unit 3. These percent reduction values were used 

by NDEP in developing its own estimate of NOx emissions, which 

form the basis for the proposed NOx limits. 

Nevada Energy‟s BART analysis for Unit 3 did not provide a 

unit-specific explanation for this difference in control 

effectiveness. In responding to comments on this issue, NDEP 

indicated that it deferred to Nevada Energy‟s operational 
38

experience in developing control efficiency data, and had no 

reason to question Nevada Energy‟s estimates.24 The case-by-case 

nature of the BART determination process does provide for the 

consideration of site-specific and unit-specific characteristics 

in the BART analysis.25 While there may be unique 

characteristics associated with Unit 3 that justify the lower 

percent reduction values used by Nevada Energy and NDEP, we do 

not find the record on this issue to be sufficiently detailed to 

support this determination. In the absence of what we consider 

sufficient justification by Nevada Energy and NDEP, we have 

evaluated Unit 3 control option emissions predicated upon 

similar levels of performance relative to Units 1 and 2. Based 

upon the Unit 3 baseline emissions relied upon by NDEP 

(described in the „NDEP‟ column in Table 4), if a percent 

reduction similar to Units 1 and 2 were applied to Unit 3 

baseline emissions, it can be expected to attain a NOx emission 

rate of 0.20 lb/MMBtu using the ROFA with Rotamix control 

option. 

B. Unit 1 through 3 Averaging Period

We are proposing to promulgate a FIP to establish a 30-day 

rolling average, averaged across all three units, as the basis 

for the NOx emission limits for RGGS Units 1 through 3. In its 

 

24 Page D-37, Appendix D and C-9, Appendix C, Nevada RH SIP. Available as 

attachments to EPA-R09-OAR-2011-0130-0003.

25 For example, when determining what control options are considered 

technically feasible at a specific unit, 70 FR 39165.
39

RH SIP, NDEP proposed NOx limits for Units 1 through 3 based 

upon a 12-month rolling average, which is a longer averaging 

period than the 30-day rolling average indicated by the BART 

Guidelines. Longer averaging periods allow operators the 

flexibility to “smooth out” short-term emission spikes by 

averaging those values with periods of lower emission rates. 

In responding to comments on this issue in its RH SIP, NDEP 

indicated that it specified the longer averaging period because 

Nevada Energy expected a high degree of operational variability 

with the ROFA with Rotamix control option based upon previous 

operational experience with ROFA.26 Although operational 

flexibility can be a legitimate consideration when establishing 

an enforceable limit, we consider use of a rolling 12-month 

averaging period instead of a rolling 30-day average to be 

inconsistent with BART Guidelines.27 We believe the fluctuations 

of the NOx emissions from each of the units is better dealt with 

by averaging the emissions from the three units to determine 

compliance over the 30-day rolling average. 

C. Control Technology Basis

In its RH SIP, NDEP proposed emission limits for Units 1 

through 3 based upon a control technology determination of ROFA 

with Rotamix. In its March 22, 2012 letter, NDEP indicated that 

 

26 Page D-60, Appendix D, Nevada RH SIP. Available as attachments to EPA-R09-OAR-2011-0130-0003.

27 70 FR 39172
40

it intends to submit an RH SIP revision that will revise the 

control technology determination to SNCR with LNB and OFA. In 

addition, the corresponding BART emission limits for NOx that 

NDEP has indicated it will establish for Units 1 through 3 are 

of equal or greater stringency than those included in the 

current RH SIP. 

In its RH SIP, NDEP estimated that SNCR with LNB and OFA 

would be capable of achieving a NOx emission rate in the range 

of 0.27 to 0.31 lb/MMBtu (as summarized in Table 1 of this 

notice). These emission rates indicate that the SNCR with LNB 

and OFA control option is less stringent than ROFA with Rotamix, 

which NDEP estimated would be capable of achieving a NOx 

emission rate in the range of 0.20 to 0.28 lb/MMBtu. As noted in 

the BART Guidelines, BART “means an emission limitation based on 

the degree of reduction achievable through the application of 

the best system of continuous emission reduction.”28 Although 

NDEP may propose a less stringent control technology 

determination in a future RH SIP revision, we would not consider 

the final BART determination to be less stringent if the 

selected control option is capable of meeting the NOx emission 

limit of 0.20 lb/MMBtu (30-day rolling average, averaged across 

all three units) established in our FIP. 

VI. EPA’s Proposed Action

 

28 70 FR 39163
41

With the exception of the NOx BART emission limit for Unit 

3 and the NOx averaging time for all three units, EPA is 

proposing to find the Nevada RH BART determination for NOx 

fulfills all the relevant requirements of CAA Section 169A and 

the Regional Haze Rule. Therefore, we are proposing to approve 

NDEP‟s conclusion that SCR is not required as BART for NOx. 

NDEP weighed the incremental cost of requiring SCR against the 

relatively small visibility improvement that would be achieved 

from installing and operating SCR. NDEP‟s incremental cost 

included costs that inappropriately increased the cost estimate. 

However, NDEP is allowed to weigh the incremental cost against 

the incremental visibility improvement. Our independent 

modeling found that incremental visibility improvement at 

adjacent Class I areas would be significantly lower than the 

improvement modeled by NDEP. This information supports our 

determination that NDEP is within the discretion allowed by the 

BART Guidelines to establish the NOx emissions limit that can be 

achieved with ROFA and Rotamix (or SNCR with LNB and OFA 

achieving the same emissions limit) as BART rather than 

requiring an emission limit consistent with SCR technology.

NDEP, however, failed to support applying a higher emission 

limit for Unit 3 and failed to provide a sufficient basis for 

approving the emissions limit on a 12-month rolling average. 

Therefore, EPA is disapproving the RGGS NOx BART determination 
42

for Unit 3 and promulgating a FIP setting the same emission 

limit for Unit 3 that NDEP set for Units 1 and 2. EPA is also 

promulgating a FIP requiring Units 1 through 3 to meet the NOx 

emissions limit of 0.20 lbs/mmbtu on a rolling 30-day average 

(across all three units). 

VII. Statutory and Executive Order Reviews 

A. Executive Order 12866: Regulatory Planning and Review

This proposed action is not a „„significant regulatory 

action‟‟ under the terms of Executive Order (EO) 12866 (58 FR 

51735, October 4, 1993), and is therefore not subject to review 

under the Executive Order. The proposed FIP applies to only one 

facility and is therefore not a rule of general applicability. 

B. Paperwork Reduction Act

This proposed action does not impose an information 

collection burden under the provisions of the Paperwork 

Reduction Act, 44 U.S.C. 3501 et seq. Under the Paperwork 

Reduction Act, a „„collection of information‟‟ is defined as a

requirement for „„answers to * * * identical reporting or 

recordkeeping requirements imposed on ten or more persons * * 

*.‟‟ 44 U.S.C. 3502(3)(A). Because the proposed FIP applies to 

just one facility, the Paperwork Reduction Act does not apply. 

See 5 CFR 1320(c). 

Burden means the total time, effort, or financial resources 

expended by persons to generate, maintain, retain, or disclose 
43

or provide information to or for a Federal agency. This includes 

the time needed to review instructions; develop, acquire,

install, and utilize technology and systems for the purposes of 

collecting, validating, and verifying information, processing 

and maintaining information, and disclosing and providing 

information; adjust the existing ways to comply with any 

requirements; train personnel to be able to respond to a 

collection of information; search data sources; complete and 

review the collection of information; and transmit or otherwise 

disclose the information. 

An agency may not conduct or sponsor, and a person is not 

required to respond to a collection of information unless it 

displays a currently valid Office of Management and Budget (OMB) 

control number. The OMB control numbers for our regulations in 

40 CFR are listed in 40 CFR part 9.

C. Regulatory Flexibility Act

The Regulatory Flexibility Act (RFA) generally requires an 

agency to prepare a regulatory flexibility analysis of any rule 

subject to notice and comment rulemaking requirements under the 

Administrative Procedure Act or any other statute unless the 

agency certifies that the rule will not have a significant 

economic impact on a substantial number of small entities. Small 

entities include small businesses, small organizations, and 

small governmental jurisdictions. 
44

For purposes of assessing the impacts of today‟s proposed 

rule on small entities, small entity is defined as: (1) A small 

business as defined by the Small Business Administration‟s (SBA) 

regulations at 13 CFR 121.201; (2) a small governmental 

jurisdiction that is a government of a city, county, town, 

school district or special district with a population of less 

than 50,000; and (3) a small organization that is any not-for 

profit enterprise which is independently owned and operated and 

is not dominant in its field. 

After considering the economic impacts of this proposed 

action on small entities, I certify that this proposed action 

will not have a significant economic impact on a substantial 

number of small entities. The Regional Haze FIP for the single 

facility being proposed today does not impose any new 

requirements on small entities. The proposed partial approval of 

the SIP, if finalized, merely approves state law as meeting 

Federal requirements and imposes no additional requirements 

beyond those imposed by state law. See Mid-Tex Electric 

Cooperative, Inc. v.FERC, 773 F.2d 327 (D.C. Cir. 1985)

D. Unfunded Mandates Reform Act (UMRA)

Under sections 202 of the Unfunded Mandates Reform Act of 

1995 („„Unfunded Mandates Act‟‟), signed into law on March 22, 

1995, EPA must prepare a budgetary impact statement to accompany 

any proposed or final rule that includes a Federal mandate that 
45

may result in estimated costs to State, local, or tribal 

governments in the aggregate; or to the private sector, of $100 

million or more (adjusted to inflation) in any 1 year. Under 

section 205, EPA must select the most cost-effective and least 

burdensome alternative that achieves the objectives of the rule 

and is consistent with statutory requirements. Section 203 

requires EPA to establish a plan for informing and advising any 

small governments that may be significantly or uniquely impacted 

by the rule. 

Under Title II of UMRA, EPA has determined that this 

proposed rule does not contain a Federal mandate that may result 

in expenditures that exceed the inflation-adjusted UMRA 

threshold of $100 million by State, local, or Tribal governments 

or the private sector in any 1 year. In addition, this proposed 

rule does not contain a significant Federal intergovernmental 

mandate as described by section 203 of UMRA nor does it contain 

any regulatory requirements that might significantly or uniquely 

affect small governments.

E. Executive Order 13132: Federalism

Federalism (64 FR 43255, August 10, 1999) revokes and 

replaces Executive Orders 12612 (Federalism) and 12875 

(Enhancing the Intergovernmental Partnership). Executive Order 

13132 requires EPA to develop an accountable process to ensure 

„„meaningful and timely input by State and local officials in 
46

the development of regulatory policies that have federalism 

implications.” “Policies that have federalism implications” is 

defined in the Executive Order to include regulations that have 

“substantial direct effects on the States, on the relationship 

between the national government and the States, or on the 

distribution of power and responsibilities among the various 

levels of government.” Under Executive Order 13132, EPA may not 

issue a regulation that has federalism implications, that 

imposes substantial direct compliance costs, and that is not 

required by statute, unless the Federal government provides the 

funds necessary to pay the direct compliance costs incurred by 

State and local governments, or EPA consults with State and 

local officials early in the process of developing the proposed 

regulation. EPA also may not issue a regulation that has 

federalism implications and that preempts State law unless the 

Agency consults with State and local officials early in the 

process of developing the proposed regulation. 

This rule will not have substantial direct effects on the 

States, on the relationship between the national government and 

the States, or on the distribution of power and responsibilities 

among the various levels of government, as specified in 

Executive Order 13132, because it merely addresses elements of 

the State‟s Regional Haze SIP that are inconsistent with the 

Regional Haze Rule. In addition, the State has indicated that it 
47

intends to submit a SIP revision, the contents of which are 

intended to match the content of the FIP proposed in this rule. 

Thus, Executive Order 13132 does not apply to this action. In 

the spirit of Executive Order 13132, and consistent with EPA 

policy to promote communications between EPA and State and local 

governments, EPA specifically solicits comment on this proposed 

rule from State and local officials.

F. Executive Order 13175: Consultation and Coordination With 

Indian Tribal Governments

Executive Order 13175, entitled Consultation and 

Coordination with Indian Tribal Governments (65 FR 67249, 

November 9, 2000), requires EPA to develop an accountable 

process to ensure “meaningful and timely input by tribal 

officials in the development of regulatory policies that have 

tribal implications.” We note that the SIP is not approved to 

apply in Tribal lands located in the State, will not impose 

substantial direct costs on tribal governments or preempt tribal 

law, and does not affect the distribution of power and 

responsibilities between the Federal Government and any Indian 

tribes. As a result, while this rule applies to an emissions 

source that is adjacent to the Moapa Reservation, it does not 

have direct tribal implications as specified by Executive Order 

13175 (65 FR 67249, November 9, 2000). However, we acknowledge 

that concerns about the environmental impacts of this facility 
48

have been raised by the Moapa Tribe. We have formally consulted 

with the Moapa Tribe regarding those concerns, and have visited 

the reservation and the facility. We will continue to work with 

the Moapa Tribe as we proceed with our action.

G. Executive Order 13045: Protection of Children From 

Environmental Health Risks and Safety Risks

Executive Order 13045: Protection of Children from 

Environmental Health Risks and Safety Risks (62 FR 19885, April 

23, 1997), applies to any rule that: (1) is determined to be 

economically significant as defined under Executive Order 12866; 

and (2) concerns an environmental health or safety risk that we 

have reason to believe may have a disproportionate effect on 

children. If the regulatory action meets both criteria, the 

Agency must evaluate the environmental health or safety effects 

of the planned rule on children, and explain why the planned

regulation is preferable to other potentially effective and 

reasonably feasible alternatives considered by the Agency. 

This rule is not subject to Executive Order 13045 because 

it does not involve decisions intended to mitigate environmental 

health or safety risks. However, to the extent this proposed 

rule will limit emissions of NOx, the rule will have a 

beneficial effect on children‟s health by reducing air 

pollution.
49

H. Executive Order 13211: Actions Concerning Regulations That 

Significantly Affect Energy Supply, Distribution, or Use

This action is not subject to Executive Order 13211 (66 FR 28355 

(May 22, 2001)), because it is not a significant regulatory 

action under Executive Order 12866.

I. National Technology Transfer and Advancement Act 

Section 12 of the National Technology Transfer and 

Advancement Act (NTTAA) of 1995 requires Federal agencies to 

evaluate existing technical standards when developing a new 

regulation. To comply with NTTAA, EPA must consider and use 

“voluntary consensus standards” (VCS) if available and 

applicable when developing programs and policies unless doing so 

would be inconsistent with applicable law or otherwise 

impractical. The EPA believes that VCS are inapplicable to this 

action. Today‟s action does not require the public to perform 

activities conducive to the use of VCS.

J. Executive Order 12898: Federal Actions To Address 

Environmental Justice in Minority Populations and Low-Income 

Populations

Executive Order 12898 (59 FR 7629, February 16, 1994), 

establishes federal executive policy on environmental justice. 

Its main provision directs federal agencies, to the greatest 

extent practicable and permitted by law, to make environmental 
50

justice part of their mission by identifying and addressing, as 

appropriate, disproportionately high and adverse human health or 

environmental effects of their programs, policies, and 

activities on minority populations and low-income populations in 

the United States. We have determined that this proposed rule, 

if finalized, will not have disproportionately high and adverse 

human health or environmental effects on minority or low-income 

populations because it increases the level of environmental 

protection for all affected populations without having any 

disproportionately high and adverse human health or 

environmental effects on any population, including any minority 

or low-income population. This proposed rule limits emissions of 

NOx from a single facility in Nevada. The partial approval of 

the SIP, if finalized, merely approves state law as meeting 

Federal requirements and imposes no additional requirements 

beyond those imposed by state law.

List of Subjects in 40 CFR Part 52

Environmental protection, Air pollution control, 

Intergovernmental relations, Nitrogen oxides, Reporting and 

recordkeeping requirements.

AUTHORITY: 42 U.S.C. 7401 et seq.
51

________________ ______________________

Dated: Jared Blumenfeld

Regional Administrator,

Region 9
52

Part 52, chapter I, title 40 of the Code of Federal 

Regulations is amended as follows:

PART 52--[AMENDED]

1. The authority citation for Part 52 continues to read as 

follows:

AUTHORITY: 42 U.S.C. 7401 et seq.

2. Part 52 is proposed to be amended by adding §52.1488(e) to

52.1488 Visibility Protection, to read as follows:

§ 52.1488(e) This paragraph (e) applies to each owner and 

operator of the coal-fired electricity generating units (EGUs) 

designated as Units 1, 2, and 3 at the Reid Gardner Generating 

Station in Clark County, Nevada.

(1) Definitions. Terms not defined below shall have the meaning 

given to them in the Clean Air Act or EPA‟s regulations 

implementing the Clean Air Act. For purposes of this section:

Ammonia injection shall include any of the following: anhydrous 

ammonia, aqueous ammonia or urea injection.

Combustion controls shall mean new low NOx burners, new overfire 

air, and/or rotating overfire air.
53

Continuous emission monitoring system or CEMS means the 

equipment required by 40 CFR Part 75 to determine compliance 

with this section.

NOx means nitrogen oxides expressed as nitrogen dioxide (NO2).

Owner/operator means any person who owns or who operates, 

controls, or supervises an EGU identified in paragraph (e) of 

this section.

Unit means any of the EGUs identified in paragraph (e) of this 

section.

Unit-wide means all of the EGUs identified in paragraph (e) of 

this section.

(2) Emission limitations - The NOx limit, expressed as nitrogen 

dioxide, for Units 1, 2, and 3 shall be 0.20 lb/MMBtu based on a 

unit-wide heat input weighted average determined over a rolling 

30-calendar day period. NO2 emissions for each calendar day 

shall be determined by summing the hourly emissions measured in 

pounds of NO2 for all operating units. Heat input for each 

calendar day shall be determined by adding together all hourly 

heat inputs, in millions of BTU, for all operating units. Each 

day the thirty-day rolling average shall be determined by adding 

together that day and the preceding 29 days‟ pounds of NO2 and 

dividing that total pounds of NO2 by the sum of the heat input 
54

during the same 30-day period. The results shall be the 30-

calendar day rolling pound per million BTU emissions of NO2. 

(3) Compliance date. The owners and operators subject to this 

section shall comply with the emissions limitations and other 

requirements of this section within 5 years from promulgation of 

this paragraph and thereafter.

(4) Testing and Monitoring. (i) The owner or operator shall use 

40 CFR Part 75 monitors and meet the requirements found in 40 

CFR Part 75. In addition to these requirements, relative 

accuracy test audits shall be performed for both the NO2 pounds 

per hour measurement and the hourly heat input measurement, and 

shall have relative accuracies of less than 20%. This testing 

shall be evaluated each time the 40 CFR Part 75 monitors undergo 

relative accuracy testing. Compliance with the emission limit 

for NO2 shall be determined by using data that is quality assured 

and considered valid under 40 CFR Part 75, and which meets the 

relative accuracy of this paragraph. 

(ii) If a valid NOx pounds per hour or heat input is not 

available for any hour for a unit, that heat input and NOx 

pounds per hour shall not be used in the calculation of the 

unit-wide rolling 30 calendar day average. Each Unit shall 

obtain at least 90% valid hours of data over each calendar 
55

quarter. 40 CFR Part 60 Appendix A Reference Methods may be used 

to supplement the Part 75 monitoring. 

(iii) Upon the effective date of the unit-wide NOx limit, the 

owner or operator shall have installed CEMS software that meets 

with the requirements of this section for measuring NO2 pounds 

per hour and calculating the unit-wide 30 calendar day rolling 

average as required in paragraph (e)(2) of this section.

(iv) Upon the completion of installation of ammonia injection on 

any of the three units, the owner or operator shall install, and 

thereafter maintain and operate, instrumentation to continuously 

monitor and record levels of ammonia consumption for that unit.

(5) Notifications. (i) The owner or operator shall notify EPA 

within two weeks after completion of installation of combustion 

controls or ammonia injection on any of the units subject to 

this section.

(ii) The owner or operator shall also notify EPA of initial 

start-up of any equipment for which notification was given in 

paragraph (e)(5)(i). 

(6) Equipment Operations. After completion of installation of 

ammonia injection on any of the three units, the owner or 

operator shall inject sufficient ammonia to minimize the NOx 
56

emissions from that unit while preventing excessive ammonia 

emissions.

(7) Recordkeeping. The owner or operator shall maintain the 

following records for at least five years: 

(i) for each unit, CEMS data measuring NOx in lb/hr, heat input 

rate per hour, the daily calculation of the unit-wide 30 

calendar day rolling lb NO2/MMbtu emission rate as required in 

paragraph (e)(2) of this section.

(ii) Records of the relative accuracy test for NOx lb/hr 

measurement and hourly heat input

(iii) Records of ammonia consumption for each unit, as recorded 

by the instrumentation required in paragraph (e)(4)(iv) of this 

section.

(8) Reporting. Reports and notifications shall be submitted to 

the Director of Enforcement Division, U.S. EPA Region IX, at 75 

Hawthorne Street, San Francisco, CA 94105. Within 30 days of the 

end of each calendar quarter after the effective date of this 

section, the owner or operator shall submit a report that lists 

the unit-wide 30 calendar day rolling lb NO2/MMBtu emission rate 

for each day. Included in this report shall be the results of 

any relative accuracy test audit performed during the calendar 

quarter.
57

(9) Enforcement. Notwithstanding any other provision in this 

implementation plan, any credible evidence or information 

relevant as to whether the unit would have been in compliance 

with applicable requirements if the appropriate performance or 

compliance test had been performed, can be used to establish 

whether or not the owner or operator has violated or is in 

violation of any standard or applicable emission limit in the 

plan.