21896 Federal Register / Vol. 77, No. 71 / Thursday, April 12, 2012 / Proposed Rules 

that this action is one of a category of 

actions that do not individually or 

cumulatively have a significant effect on 

the human environment. A preliminary 

environmental analysis checklist 

supporting this preliminary 

determination is available in the docket 

where indicated under ADDRESSES. This 

proposed rule involves the 

establishment of a safety zone and 

therefore paragraph (34)(g) of figure 

2–1 applies. We seek any comments or 

information that may lead to the 

discovery of a significant environmental 

impact from this proposed rule. 

List of Subjects in 33 CFR Part 165 

Harbors, Marine safety, Navigation 

(water), Reporting and recordkeeping 

requirements, Security measures, 

Waterways. 

For the reasons discussed in the 

preamble, the Coast Guard proposes to 

amend 33 CFR part 165 as follows: 

PART 165—REGULATED NAVIGATION 

AREAS AND LIMITED ACCESS AREAS 

1. The authority citation for part 165 

continues to read as follows: 

Authority: 33 U.S.C. 1231; 46 U.S.C. 

Chapter 701, 3306, 3703; 50 U.S.C. 191, 195; 

33 CFR 1.05–1, 6.04–1, 6.04–6, and 160.5; 

Pub. L. 107–295, 116 Stat. 2064; Department 

of Homeland Security Delegation No. 0170.1. 

2. Add § 165.T09–0200 to read as 

follows: 

§ 165.T09–0200 Safety Zone International 

Bridge 50th Anniversary Celebration 

Fireworks, St. Mary’s River, U.S. Army 

Corps of Engineers Locks, Sault Sainte 

Marie, MI. 

(a) Location. The following area is a 

temporary safety zone: All U.S. 

navigable waters of the St. Mary’s River 

within a 750-foot radius around the 

eastern portion of the U.S. Army Corp 

of Engineers Soo Locks North East Pier, 

centered in position: 46°30′19.66′′ N, 

084°20′31.61′′ W [DATUM: NAD 83]. 

(b) Effective and Enforcement period. 

This regulation is effective and will be 

enforced from 10 p.m. until 12 p.m. on 

June 28, 2012. 

(1) The Captain of the Port, Sector 

Sault Sainte Marie may suspend at any 

time the enforcement of the safety zone 

established under this section. 

(2) The Captain of the Port, Sector 

Sault Sainte Marie, will notify the 

public of the enforcement and 

suspension of enforcement of the safety 

zone established by this section via any 

means that will provide as much notice 

as possible to the public. These means 

might include some or all of those listed 

in 33 CFR 165.7(a). The primary method 

of notification, however, will be through 

Broadcast Notice to Mariners and local 

Notice to Mariners. 

(c) Definitions. The following 

definitions apply to this section: 

(1) Designated representative means 

any Coast Guard commissioned, 

warrant, or petty officer designated by 

the Captain of the Port Sault Sainte 

Marie to monitor these safety zones, 

permit entry into these safety zones, 

give legally enforceable orders to 

persons or vessels within these safety 

zones, or take other actions authorized 

by the Captain of the Port. 

(2) Public vessel means a vessel 

owned, chartered, or operated by the 

United States or by a State or political 

subdivision thereof. 

(d) Regulations. (1) The general 

regulations in 33 CFR 165.23 apply. 

(2) All persons and vessels must 

comply with the instructions of the 

Coast Guard Captain of the Port Sault 

Sainte Marie or a designated 

representative. Upon being hailed by the 

U.S. Coast Guard by siren, radio, 

flashing light or other means, the 

operator of a vessel shall proceed as 

directed. 

(3) When the safety zone established 

by this section is being enforced, all 

vessels must obtain permission from the 

Captain of the Port Sault Sainte Marie 

or his or her designated representative 

to enter, move within, or exit that safety 

zone. Vessels and persons granted 

permission to enter the safety zone shall 

obey all lawful orders or directions of 

the Captain of the Port or his or her 

designated representative. While within 

the safety zone, all vessels shall operate 

at the minimum speed necessary to 

maintain a safe course. 

(e) Exemption. Public vessels, as 

defined in paragraph (c) of this section, 

are exempt from the requirements in 

this section. 

Dated: March 28, 2012. 

J.C. McGuiness, 

Captain, U.S. Coast Guard, Captain of the 

Port Sault Sainte Marie. 

[FR Doc. 2012–8808 Filed 4–11–12; 8:45 am] 

BILLING CODE 9110–04–P 

ENVIRONMENTAL PROTECTION 

AGENCY 

40 CFR Part 52 

[EPA–R09–OAR–2011–0130, FRL–9658–5] 

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 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 May 14, 2012. 

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 Web site 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: 

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Federal Register / Vol. 77, No. 71 / Thursday, April 12, 2012 / Proposed Rules 21897 

1. Federal Rulemaking portal: http:// 

www.regulations.gov. Follow the on-line 

instructions for submitting comments. 

2. Email: Webb.Thomas@epa.gov. 

3. Fax: 415–947–3579 (Attention: 

Thomas Webb) 

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 a.m.–4:30 p.m., 

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 email. 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 email comment directly 

to EPA, without going through http:// 

www.regulations.gov, EPA will include 

your email 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 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, 9–5:30 PST, 

excluding federal holidays. 

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 

(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 

(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 

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 

discussion please see our prior 

proposed action at 76 FR 36450 (June 

22, 2011). 

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21898 Federal Register / Vol. 77, No. 71 / Thursday, April 12, 2012 / Proposed Rules 

1See 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. 

2Both reports can be found as attachments to 

EPA–R09–OAR–2011–0130–0062, with supporting 

information located in –0063. 

3 77 FR 17334. 

4Email dated December 22, 2011, from Colleen 

McKaughan (EPA) to Mike Elges (NDEP) and others. 

5Email dated March 14, 2012, from Colleen 

McKaughan (EPA) to Mike Elges (NDEP). 

6Letter dated March 22, 2012 from Mike Elges 

(NDEP) to Deborah Jordan (EPA). 

7As 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. 

8Letter dated March 22, 2012, from Mike Elges 

(NDEP) to Deborah Jordan (EPA). 

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

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 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 

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 three-unit 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 

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 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 

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Federal Register / Vol. 77, No. 71 / Thursday, April 12, 2012 / Proposed Rules 21899 

9 In NDEP/Nevada Energy’s analysis, and in our 

analysis, the highest impacted Class I area is Grand 

Canyon National Park. 

10The set of ‘‘major stationary sources’’ 

potentially subject to BART is listed in CAA section 

169A(g)(7). 11 77 FR 17334. 

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 

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 sources 10 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 

Successful implementation of the 

regional haze program will require longterm 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 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 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 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. 

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12EPA approved that portion of NDEP’s BART 

determination for RGGS on December 13, 2011. 

C. Evaluation of Nevada’s NOX BART 

Determination for Reid Gardner 

Generating Station 

Background: Reid Gardner is a coalfueled, 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 BARTeligible, and were determined by NDEP 

to be subject to BART. Each of these 

units produces about 100 MW with 

steam boilers that drive turbinegenerators. 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 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 

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 

efficiency 1

(%) 

Emission 

rate 1

(lb/MMBtu) 

Emission 

reduction 1

(ton/yr) 

Annualized 

costs 1

($MM) 

Average cost 

effectiveness 1

($/ton) 

Incremental cost 

effectiveness 1

($/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 

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 

1As 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. 

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13Revised NDEP Reid Gardner BART 

Determination Review, page 6. Available as Docket 

Item No. EPA–R09–OAR–2011–0130–0005. 

14See 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– 

OAR–2011–0130–0062). 

15These items were primarily noted in the expert 

report by Petra Pless/Bill Powers (attachment to 

EPA–R09–OAR–2011–0130–0062). 

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 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 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 

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. 

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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 total of the impacts from 

the three individual units, which Nevada Energy 

modeled separately. 

17From 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. 

TABLE 3—SUMMARY OF NEVADA ENERGY ESTIMATES OF VISIBILITY BENEFIT 16

Control option 

Visibility improvement (from WRAP baseline) 17 Visibility 

improvement 

(incremental, 

from control) RGGS1 

(dv) 

RGGS2 

(dv) 

RGGS3 

(dv) 

Total 

(dv) Total 

(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. 

TABLE 4—COMPARISON OF NEVADA ENERGY AND NDEP CONTROL TECHNOLOGY EMISSION ESTIMATES

Control option 

Nevada energy NDEP 

Emission 

factor 1

(lb/MMBtu) 

Control 

efficiency 2

(%) 

Emission 

factor 3

(lb/MMBtu) 

Control 

efficiency 3

(%) 

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 

1From each respective unit’s NVE BART Analysis, Table 3–1. Available in Docket Item No. EPA–R09–OAR–2011–0130–0007. 

2From each respective unit’s NVE BART Analysis, Table 3–2. Available in Docket Item No. EPA–R09–OAR–2011–0130–0007. 

3As 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’’. 

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19The 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. 

20We 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. 

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 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. 

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 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 

indicate 90 percent NOX reduction.20

We have elected to model 0.06 lb/ 

MMBtu based on a selection of a midrange 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 

Impact 1

(all three 

units) 

(dv) 

Visibility improvement 

From 

baseline 

(dv) 

Incremental, 

from 

previous 

option 

(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 

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21Baseline 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. 

22Per 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. 

TABLE 5—SUMMARY OF VISIBILITY IMPACTS—Continued 

Control option 

Visibility 

Impact 1

(all three 

units) 

(dv) 

Visibility improvement 

From 

baseline 

(dv) 

Incremental, 

from 

previous 

option 

(dv) 

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 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 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, 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 

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 

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Federal Register / Vol. 77, No. 71 / Thursday, April 12, 2012 / Proposed Rules 21905 

23 70 FR 39172. 

24Page D–37, Appendix D and C–9, Appendix C, 

Nevada RH SIP. Available as attachments to EPA– 

R09–OAR–2011–0130–0003. 

25For example, when determining what control 

options are considered technically feasible at a 

specific unit, 70 FR 39165. 

26Page D–60, Appendix D, Nevada RH SIP. 

Available as attachments to EPA–R09–OAR–2011– 

0130–0003. 27 70 FR 39172. 28 70 FR 39163. 

limit) as BART, completion of the BART 

process requires establishing 

enforceable emission limits that reflect 

the BART 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 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 1 Through 3 Averaging Period 

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 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 sitespecific 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 3 Emission Limit 

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 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 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. Federal Implementation Plan To 

Address NOX BART for Reid Gardner 

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 

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21906 Federal Register / Vol. 77, No. 71 / Thursday, April 12, 2012 / Proposed Rules 

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 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. EPA’s Proposed Action 

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 

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. 

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 

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 costeffective 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 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 

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Federal Register / Vol. 77, No. 71 / Thursday, April 12, 2012 / Proposed Rules 21907 

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 

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 

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. 

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 

VIII. Statutory and Executive Order 

Reviews 

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 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. 

Dated: April 2, 2012. 

Jared Blumenfeld, 

Regional Administrator, Region 9. 

For the reasons stated in the 

preamble, Part 52, chapter I, title 40 of 

the Code of Federal Regulations is 

proposed to be 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 amended by adding 

§ 52.1488(e) to 52.1488 Visibility 

Protection, to read as follows: 

§ 52.1488 Visibility protection. 

* * * * * 

(e) This paragraph (e) applies to each 

owner and operator of the coal-fired 

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21908 Federal Register / Vol. 77, No. 71 / Thursday, April 12, 2012 / Proposed Rules 

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. 

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 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 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

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. 

(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. 

[FR Doc. 2012–8713 Filed 4–11–12; 8:45 am] 

BILLING CODE 6560–50–P 

ENVIRONMENTAL PROTECTION 

AGENCY 

40 CFR Part 52 

[EPA–R03–OAR–2009–0882; FRL–9656–9] 

Approval and Promulgation of Air 

Quality Implementation Plans; 

Pennsylvania; Streamlining 

Amendments to the Plan Approval 

Regulations 

AGENCY: Environmental Protection 

Agency (EPA). 

ACTION: Proposed rule. 

SUMMARY: EPA is proposing to grant 

limited approval to a State 

Implementation Plan (SIP) revision 

submitted by the Pennsylvania 

Department of Environmental Protection 

(PADEP) on April 14, 2009. The revision 

pertains to PADEP’s plan approval 

requirements for the construction, 

modification, and operation of sources, 

and is primarily intended to streamline 

the process for minor permitting 

actions. This action is being taken under 

the Clean Air Act (CAA). 

DATES: Written comments must be 

received on or before May 14, 2012. 

ADDRESSES: Submit your comments, 

identified by Docket ID Number EPA– 

R03–OAR–2009–0882 by one of the 

following methods: 

A. www.regulations.gov. Follow the 

on-line instructions for submitting 

comments. 

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