Federal Register / Vol. 70, No. 202 / Thursday, October 20, 2005 / Proposed Rules 61081 

ENVIRONMENTAL PROTECTION 

AGENCY 

40 CFR Parts 51 and 52 

[FRL–7985–7; E-Docket ID No. OAR–2005–

0163] 

RIN 2060–AN28 

Prevention of Significant Deterioration, 

Nonattainment New Source Review, 

and New Source Performance 

Standards: Emissions Test for Electric 

Generating Units 

AGENCY: Environmental Protection 

Agency (EPA). 

ACTION: Proposed rule. 

SUMMARY: The EPA (we) is proposing to 

revise the emissions test for existing 

electric generating units (EGUs) that are 

subject to the regulations governing the 

Prevention of Significant Deterioration 

(PSD) and nonattainment major New 

Source Review (NSR) programs 

(collectively ‘‘NSR’’) mandated by parts 

C and D of title I of the Clean Air Act 

(CAA or Act). The revised emissions test 

is the same as that in the New Source 

Performance Standards (NSPS) program 

under CAA section 111(a)(4). For 

existing EGUs, we are proposing to 

compare the maximum hourly 

emissions achievable at that unit during 

the past 5 years to the maximum hourly 

emissions achievable at that unit after 

the change to determine whether an 

emissions increase would occur. 

Alternatively, we are soliciting public 

comment on a major NSR emissions test 

for existing EGUs that would compare 

maximum hourly emissions achieved 

before a change to the maximum hourly 

emissions achieved after the change. We 

are also soliciting public comment on 

adopting an NSR emissions test based 

on mass of emissions per unit of energy 

output. In addition, we are soliciting 

comment on whether to revise the NSPS 

regulations to include a maximum 

achieved emissions test or an outputbased emissions test, either in lieu of or 

in addition to the maximum achievable 

hourly emissions test. Today’s proposal 

would not affect new EGUs, which 

would continue to be subject to major 

NSR preconstruction review and to the 

NSPS program. The proposed rule 

would only apply prospectively to 

changes at existing EGUs potentially 

covered by major NSR and the NSPS 

programs. 

These proposed regulations interpret 

CAA section 111(a)(4), in the context of 

NSR and NSPS, for physical changes 

and changes in the method of operation 

at existing EGUs. The proposed 

regulations would establish a uniform 

emissions test nationally under the 

NSPS and NSR programs for existing 

EGUs. The proposed regulations would 

also promote the safety, reliability, and 

efficiency of EGUs. 

DATES: Comments. Comments must be 

received on or before December 19, 

2005. 

Public Hearing. If anyone contacts us 

requesting to speak at a public hearing 

November 9, 2005, we will hold a 

public hearing approximately 30 days 

after publication in the Federal 

Register. 

ADDRESSES: Submit your comments, 

identified by Docket ID No. OAR–2005–

0163 by one of the following methods: 

• Federal eRulemaking Portal: http:// 

www.regulations.gov. Follow the on-line 

instructions for submitting comments. 

• Agency Web site: http:// 

www.epa.gov/edocket. EDOCKET, EPA’s 

electronic public docket and comment 

system, is EPA’s preferred method for 

receiving comments. Follow the on-line 

instructions for submitting comments. 

• E-mail: a-and-rdocket@epamail.epa.gov. 

• Fax: 202–566–1741. 

• Mail: Attention Docket ID No. 

OAR–2005–0163, U.S. Environmental 

Protection Agency, EPA West (Air 

Docket), 1200 Pennsylvania Avenue, 

Northwest, Mail Code: 6102T, 

Washington, DC 20460. In addition, 

please mail a copy of your comments on 

the information collection provisions to 

the Office of Information and Regulatory 

Affairs, Office of Management and 

Budget (OMB), Attn: Desk Officer for 

OMB, 725 17th Street, Northwest, 

Washington, DC 20503. 

• Hand Delivery: U.S. Environmental 

Protection Agency, EPA West (Air 

Docket), 1301 Constitution Avenue, 

Northwest, Room B102, Washington, DC 

20004, Attention Docket ID No. OAR–

2005–0163. Such deliveries are only 

accepted during the Docket’s normal 

hours of operation, and special 

arrangements should be made for 

deliveries of boxed information. 

Instructions: Direct your comments to 

Docket ID No. OAR–2005–0163. EPA’s 

policy is that all comments received 

will be included in the public docket 

without change and may be made 

available online at http://www.epa.gov/ 

edocket, 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 EDOCKET, 

regulations.gov, or e-mail. The EPA 

EDOCKET and the Federal 

regulations.gov Web sites are 

‘‘anonymous access’’ systems, 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 

EDOCKET or regulations.gov, your email address will be automatically 

captured and included 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, avoid any 

form of encryption, and be free of any 

defects or viruses. For additional 

information about EPA’s public docket 

visit EDOCKET on-line or see the 

Federal Register of May 31, 2002 (67 FR 

38102). For additional instructions on 

submitting comments, go to section I..B. 

of the SUPPLEMENTARY INFORMATION

section of this document. 

Docket: All documents in the docket 

are listed in the EDOCKET index at 

http://www.epa.gov/edocket. Although 

listed in the index, some information is 

not publicly available, i.e., CBI or other 

information whose disclosure is 

restricted by statute. Certain other 

material, such as copyrighted material, 

is not placed on the Internet and will be 

publicly available only in hard copy 

form. Publicly available docket 

materials are available either 

electronically in EDOCKET or in hard 

copy at the U.S. Environmental 

Protection Agency, EPA West (Air 

Docket), 1301 Constitution Avenue, 

Northwest, Room B102, Washington, 

DC. Attention Docket ID No. OAR–

2005–0163. The Public Reading Room is 

open from 8:30 a.m. to 4:30 p.m., 

Monday through Friday, excluding legal 

holidays. The telephone number for the 

Public Reading Room is (202) 566–1744, 

and the telephone number for the Air 

Docket is (202) 566–1742. 

FOR FURTHER INFORMATION CONTACT: Ms. 

Janet McDonald, Information Transfer 

and Program Integration Division 

(C339–03), U.S. Environmental 

Protection Agency, Research Triangle 

Park, NC 27711, telephone number: 

(919) 541–1450; fax number : (919) 541–

5509, or electronic mail at 

mcdonald.janet@epa.gov. 

SUPPLEMENTARY INFORMATION: 

61082 Federal Register / Vol. 70, No. 202 / Thursday, October 20, 2005 / Proposed Rules 

I. General Information 

A. What Are the Regulated Entities? 

Entities potentially affected by the 

subject rule for today’s action are fossilfuel fired boilers, turbines, and internal 

combustion engines, including those 

that serve generators producing 

electricity, generate steam or cogenerate 

electricity and steam. 

Industry group SIC a NAICSb

Electric Services ......................................... 491 221111, 221112, 221113, 221119, 221121, 221122. 

Federal government ................................... 221121 Fossil-fuel fired electric utility steam generating units owned by the Federal government. 

State/local/Tribal government .................... 22112 Fossil-fuel fired electric utility steam generating units owned by municipalities. Fossilfuel fired electric utility steam generating units in Indian country. 

aStandard Industrial Classification. 

b North American Industry Classification System. 

1Establishments owned and operated by Federal, State, or local government are classified according to the activity in which they are engaged. 

Entities potentially affected by the 

subject rule for today’s action also 

include State, local, and tribal 

governments. 

B. How Should I Submit CBI to the 

Agency? 

1. Submitting CBI. Do not submit this 

information that you consider to be CBI 

electronically through EDOCKET, 

regulations.gov or e-mail. Clearly mark 

the part or all of the information that 

you claim to be CBI. For CBI 

information in a disk or CD ROM that 

you mail to EPA, mark on the CD ROM 

the specific information that is claimed 

as CBI. In addition to one complete 

version of the comment that includes 

information claimed as CBI, a copy of 

the comment that does not contain the 

information claimed as CBI must be 

submitted for inclusion in the public 

docket. Information so marked will not 

be disclosed except in accordance with 

procedures set forth in 40 CFR part 2. 

Also, send an additional copy clearly 

marked as above not only to the Air 

Docket but to: Mr. Roberto Morales, 

OAQPS Document Control Officer, 

(C339–03), U.S. Environmental 

Protection Agency, Research Triangle 

Park, NC 27711, Attention Docket ID 

No. OAR–2005–0163. 

C. What Should I Consider as I Prepare 

My Comments for EPA? 

When submitting comments, 

remember to: 

1. Identify the rulemaking by docket 

number and other identifying 

information (subject heading, Federal 

Register date and page number). 

2. Follow directions—The agency may 

ask you to respond to specific questions 

or organize comments by referencing a 

Code of Federal Regulations (CFR) part 

or section number. 

3. Explain why you agree or disagree; 

suggest alternatives and substitute 

language for your requested changes. 

4. Describe any assumptions and 

provide any technical information and/ 

or data that you used. 

5. If you estimate potential costs or 

burdens, explain how you arrived at 

your estimate in sufficient detail to 

allow for it to be reproduced. 

6. Provide specific examples to 

illustrate your concerns, and suggest 

alternatives. 

7. Explain your views as clearly as 

possible, avoiding the use of profanity 

or personal threats. 

8. Make sure to submit your 

comments by the comment period 

deadline identified. 

D. How Can I Find Information About a 

Possible Public Hearing? 

People interested in presenting oral 

testimony or inquiring as to whether a 

hearing is to be held should contact Ms. 

Chandra Kennedy, Integrated 

Implementation Group, Information 

Transfer and Program Integration 

Division (C339–03), U.S. Environmental 

Protection Agency, Research Triangle 

Park, NC 27711, telephone number (919) 

541–5319, at least 2 days in advance of 

the public hearing. People interested in 

attending the public hearing should also 

contact Ms. Kennedy to verify the time, 

date, and location of the hearing. The 

public hearing will provide interested 

parties the opportunity to present data, 

views, or arguments concerning these 

proposed changes. 

E. How Is This Preamble Organized? 

The information presented in this 

preamble is organized as follows: 

I. General Information 

A. What Are the Regulated Entities? 

B. How Should I Submit CBI Material to 

the Agency? 

C. What Should I Consider as I Prepare My 

Comments? 

D. How Can I Find Information About a 

Possible Public Hearing? 

E. How Is This Preamble Organized? 

II. Overview 

III. Background on EGU Emissions and 

Requirements 

A. SO2 and NOX Requirements Before 1990 

B. SO2 and NOX Requirements After 1990 

C. Requirements for Pollutants Other Than 

SO2 and NOX

IV. Today’s Proposed Rule 

A. Background on Existing Regulations 

B. What We Are Proposing 

1. Test for EGUs Based on Maximum 

Achievable Hourly Emissions 

2. Test for EGUs Based on Maximum 

Achieved Hourly Emissions 

3. Emissions Test Based on Energy Output 

C. Pollutants to Which the Revised 

Applicability Test Applies 

D. Significant Emissions Rates 

E. Eliminating Netting 

F. Benefits of Maximum Achievable Hourly 

Emissions Test 

G. Would States Be Required To Adopt the 

Revised Emissions Test? 

V. Statutory and Regulatory History and 

Legal Rationale 

A. The NSPS Program 

B. The Major NSR Program 

C. Legal Rationale 

1. Maximum Achievable Hourly Emissions 

Test 

2. Maximum Achieved Hourly Emissions 

Test 

VI. Statutory and Executive Order Reviews 

A. Executive Order 12866—Regulatory 

Planning and Review 

B. Paperwork Reduction Act 

C. Regulatory Flexibility Act (RFA) 

D. Unfunded Mandates Reform Act 

E. Executive Order 13132—Federalism 

F. Executive Order 13175—Consultation 

and Coordination With Indian Tribal 

Governments 

G. Executive Order 13045—Protection of 

Children From Environmental Health 

Risks and Safety Risks 

H. Executive Order 13211—Actions 

Concerning Regulations That 

Significantly Affect Energy Supply, 

Distribution, or Use 

I. National Technology Transfer and 

Advancement Act 

II. Overview 

In today’s action, we are proposing to 

revise the emissions test for existing 

EGUs that are subject to the regulations 

in the major NSR programs mandated by 

parts C and D of title I of the CAA. The 

revised emissions test is the same as 

that in the NSPS under CAA section 

Federal Register / Vol. 70, No. 202 / Thursday, October 20, 2005 / Proposed Rules 61083 

2The Court allowed for the possibility that EPA 

may change the test that applies through future 

rulemaking. See item 0015 in E-Docket OAR–2005–

0163. 

3We continue to respectfully disagree with the 

Fourth Circuit’s decision in Duke Energy (item 0015 

in E-Docket OAR–2005–0163) and continue to 

believe that we have the authority to define 

‘‘modification’’ differently in the NSPS and NSR 

programs. However, we believe that the action that 

we proposed today is an appropriate exercise of our 

discretion. 

111. For existing EGUs, we are 

proposing to compare the maximum 

hourly emissions achievable at that unit 

during the past 5 years to the maximum 

hourly emissions achievable at that unit 

after the change to determine whether 

an emissions increase would occur. This 

maximum achievable hourly emissions 

test would apply to emissions from 

existing EGUs. Today’s proposal would 

not affect new EGUs, which would 

continue to be subject to major NSR 

preconstruction review. These proposed 

regulations interpret CAA section 

111(a)(4), in the context of NSR, for 

physical changes and changes in the 

method of operation at existing EGUs. 

Alternatively, we are soliciting public 

comment on a major NSR emissions test 

for existing EGUs that would compare 

maximum hourly emissions achieved 

before a change to the maximum hourly 

emissions achieved after the change. 

The test based on maximum achievable 

hourly emissions is our preferred test, 

but we are also soliciting comment on 

this test based on maximum achieved 

hourly emissions. 

We also request comment on adopting 

an NSR emissions test based on mass of 

emissions per unit of energy output, 

such as lb/MW hour or nanograms per 

Joule. As we discuss in more detail in 

Section IV.B.3. of this preamble, an 

output-based emissions test encourages 

use of energy efficient EGU that displace 

less efficient, more polluting units. 

We also request comment on 

extending the proposed emission 

increase tests to the NSPS program. 

Specifically, we are also soliciting 

comment on whether to revise 40 CFR 

60.14 to include a maximum achieved 

emissions test or an output-based 

emissions test, either in lieu of or in 

addition to the maximum achievable 

hourly emissions test in the current 

regulations. 

The proposed regulations would 

establish a uniform emissions test 

nationally under the NSPS and NSR 

programs for existing EGUs. The need to 

provide national consistency for EGUs 

is apparent following a recent Fourth 

Circuit Court of Appeals decision. On 

June 15, 2005, the Fourth Circuit Court 

of Appeals ruled that EPA must use a 

consistent definition of the term 

‘‘modification’’ for the purposes of both 

the NSPS program under section 111 of 

the Act and NSR program under parts C 

and D of the Act. The Court further 

ruled that because EPA had 

promulgated NSPS regulations with a 

test based on increases in a plant’s 

hourly rate of emissions prior to 

enactment of the PSD provision of the 

statute, and the PSD regulations had to 

be interpreted congruently to include 

the same hourly test.2 See United States 

v. Duke Energy Corp., No. 04–1763 (4th 

Cir. June 15, 2005). The Fourth Circuit 

denied the United States’ petition for 

rehearing concerning this decision, 

although the deadline for filing a 

petition for certiorari has not yet run.3

The NSPS program applies a maximum 

achievable hourly emissions rate test to 

determine whether a physical change or 

change in the operation (physical or 

operational change) results in an 

emissions increase. Once the mandate is 

issued in the Duke Energy case, the 

NSPS test will apply in all Fourth 

Circuit States, unless the NSR test in 

those States’ implementation plans is 

more stringent than the NSPS test. This 

holding creates a potential disparity in 

the way we interpret the program in 

States in the Fourth Circuit compared to 

States in other Circuits in the country. 

By finalizing today’s proposed rule, we 

would provide nationwide consistency 

in how States implement the major NSR 

program for EGUs and establish a test 

consistent with the Fourth Circuit’s 

holding in Duke Energy. We would also 

make a uniform emissions test under the 

NSPS and NSR programs for existing 

EGUs. 

We believe a uniform national 

emissions test has particular merit 

considering the substantial emissions 

reductions from other CAA 

requirements that are more efficient 

than major NSR, which we describe in 

Section III of this preamble. 

Furthermore, the proposed regulations 

allow owner/operators to make changes 

that, without increasing existing 

capacity, promote the safety, reliability, 

and efficiency of EGUs. The current 

major NSR approach discourages 

sources from replacing components, and 

encourages them to replace components 

with inferior components or to 

artificially constrain production in other 

ways. This behavior does not advance 

the central policy goals of the major 

NSR program as applied to existing 

sources. The central policy goal is not 

to limit productive capacity of major 

stationary sources, but rather to ensure 

that they will install state-of-the-art 

pollution controls at a juncture where it 

otherwise makes sense to do so. We also 

do not believe the outcomes produced 

by the approach we have been taking 

have significant environmental benefits 

compared with the approach we are 

proposing today. 

In the following sections of this 

preamble, we provide details on the 

EGU requirements and emissions, 

today’s proposed rule, and the legal 

basis for our proposal. We request 

public comment on all aspects of 

today’s proposed action. We intend to 

publish a supplemental proposal in the 

near future that will include proposed 

regulatory language, as well as 

additional data and information. 

III. Background on EGU Requirements 

and Emissions 

In this section we describe the 

regulatory history and programs 

applying to EGUs. These include the 

command-and-control strategies such as 

NSPS and major NSR that went into 

effect before 1990, as well as the more 

efficient programs since 1990 that have 

achieved substantial reductions in EGU 

emissions. 

A. SO2 and NOX Requirements Before 

1990 

Beginning in 1970, the CAA and our 

implementing regulations have imposed 

numerous requirements on sulfur 

dioxide (SO2) and nitrous oxide (NOX) 

emissions from utilities. In the early 

regulatory history under the CAA, these 

requirements were limited to the NSPS 

and major NSR programs. The NSPS 

program applies to EGUs and other 

stationary sources of pollutants, 

including SO2, NOX, particulate matter 

(PM), carbon monoxide (CO), ozone, 

and lead, among others. The Act 

required us to develop NSPS for a 

number of source categories, including 

coal-fired power plants. The first NSPS 

for EGUs (40 CFR part 60, subpart D) 

required new units to limit SO2

emissions either by using scrubbers or 

by using low sulfur coal. It required 

limits on NOX emissions through the 

use of low NOX burners. A new NSPS 

(40 CFR part 60, subpart Da), 

promulgated in 1978, tightened the 

standards for SO2, requiring scrubbers 

on all new units. 

Federal preconstruction permitting for 

EGUs and other new stationary sources 

was considered in 1970, but not added 

to the CAA until it was amended again 

in 1977. The Federal preconstruction 

program for major stationary sources is 

commonly called the major NSR 

program. As we discuss in further detail 

in Section V.B. of this preamble, the 

major NSR program required emission 

limitations based on Best Available 

Control Technology (BACT) and Lowest 

61084 Federal Register / Vol. 70, No. 202 / Thursday, October 20, 2005 / Proposed Rules 

4The Acid Rain program generally applies to all 

fossil-fuel fired combustion devices that, if 

commencing commercial operation before 

November 15, 1990, serve on or after November 15, 

1990 a generator greater than 25 MW producing 

electricity for sale and that, if commencing 

commercial operation on or after November 15, 

1990, serve on or after November 15, 1990 any 

generator producing electricity for sale. The Acid 

Rain program does not apply to a small portion of 

the national EGU inventory, including some 

cogeneration units (many of which are natural-gas 

fired), certain independent power producers, and 

solid waste incineration units. 

5See 63 FR 57356, October 27, 1998 (Item 002 in 

E–Docket OAR–2005–0163). 

6The proposed test would not apply to all 

cogeneration units. It would apply only to those 

EGU that §§ 96.104, 96.204, and 96.304 identify. On 

August 24, 2005 [70 FR 49708; see item 0029 in EDocket OAR–2005–0163], we proposed changes to 

§§ 96.104 and 96.204 to exclude units (serving a 

greater-than-25 MW generator) that stopped 

operating before November 15, 1990 and do not 

resume. In this notice, we also proposed changes to 

the definition of ‘‘EGU’’ to exclude certain solid 

waste incineration units. 

7For allowances of vintage years 2010–2014, each 

allowance authorized the emission of half a ton of 

SO2 for a calendar year. For allowances of vintage 

years 2015 and beyond, each allowance authorizes 

the emission of 0.35 tons of SO2 for a calendar year. 

See item 0019 in E–Docket OAR–2005–0163–70 FR 

25258, May 12, 2005. See also 40 CFR 96.202. 

Achievable Emission Rate (LAER) 

controls. 

The NSPS and major NSR programs 

imposed limitations on EGU SO2 and 

NOX emissions at individual sources 

based on control technology 

performance. They did not set specific 

limits on the total regional or national 

emissions from EGUs. Neither of these 

programs apply to EGUs that were 

already in existence before the 

regulations were effective, unless these 

EGUs choose to modify. Thus, neither 

program applies to all EGUs. Before 

1990, however, the major NSR program 

did provide States one of the few 

opportunities to mitigate rising levels of 

air pollution through regulation of 

possible emissions increases from 

existing sources. Therefore, the program 

was consistent with Congress’ directive 

that the major NSR program be tailored 

to balance the ‘‘need for environmental 

protection against the desires to 

encourage economic growth.’’

B. SO2 and NOX Requirements After 

1990 

The 1990 Amendments to the CAA 

imposed a number of new requirements 

on EGUs. The Acid Rain program, 

established under title IV of the 1990 

CAA Amendments, requires major 

reductions of SO2 and NOX emissions. 

The SO2 program, which covers most 

EGU in the contiguous United States,4

sets a permanent cap on the total 

amount of SO2 that can be emitted by 

EGUs at about one-half of the amount of 

SO2 these sources emitted in 1980. 

Using a market-based cap-and-trade 

mechanism such as the Acid Rain SO2

program allows flexibility for individual 

combustion units to select their own 

methods of compliance. The program 

requires NOX emission limitations for 

certain coal-fired EGUs, with the 

objective of achieving a 2 million ton 

reduction from projected NOX emission 

levels that would have been emitted in 

the year 2000 without implementation 

of title IV. 

The Acid Rain program at 40 CFR 

parts 72 through 78 comprises two 

phases for SO2 and NOX. Phase I 

applied primarily to the largest coalfired electric generation sources from 

1995 through 1999 for SO2 and from 

1996 through 1999 for NOX. Phase II for 

both pollutants began in 2000. For SO2, 

it applies to thousands of combustion 

units generating electricity nationwide; 

for NOX it generally applies to affected 

units nationwide that burned coal 

during the period between 1990 and 

1995. The Acid Rain program has led to 

the installation of scrubbers on a 

number of existing coal-fired units, as 

well as significant fuel switching to 

lower sulfur coals. Under the NOX

provisions of title IV, most existing coalfired units were required to install low 

NOX burners. 

The 1990 CAA also placed much 

greater emphasis on interstate transport 

of ozone and its precursors, and on 

control of NOX to reduce ozone 

nonattainment. This led to the 

formation of several regional NOX

trading programs. In 1998, EPA 

promulgated regulations, known as the 

NOX SIP Call,5 that required 21 states in 

the eastern United States and the 

District of Columbia to reduce NOX

emissions that contributed to 

nonattainment in downwind States. 

EPA based the reduction requirements 

on, and States implemented those 

requirements through a cap-and-trade 

approach targeted to EGUs. This 

program has resulted in the installation 

of significant amounts of selective 

catalytic reduction (SCR). The first SCR 

application in the U.S. on a coal-fired 

boiler started operating in 1993. At the 

end of 2002, 56 U.S. boilers were 

operating with SCR. 

By notice dated May 12, 2005 [70 FR 

25162], we promulgated the Clean Air 

Interstate Rule (CAIR) to reduce 

interstate transport of SO2 and NOX

emissions. This rule established 

statewide emission reduction 

requirements for SO2 and NOX for States 

in the CAIR region. The emission 

reduction requirements are based on 

controls that are known to be highly 

cost effective for EGUs. This program 

was based on extensive experience in 

the Acid Rain and NOX SIP Call capand-trade programs for major sources of 

SO2 and NOX. 

In the CAIR, we took final action 

requiring 28 States and the District of 

Columbia to adopt and submit revisions 

to their State Implementation Plans 

(SIPs), under the requirements of CAA 

section 110(a)(2)(D), that would 

eliminate specified amounts of SO2 and/ 

or NOX emissions. In developing the 

CAIR, we limited the requirements to 

those 28 States because we did not find 

that emissions from other States 

contribute significantly to downwind 

PM2.5 or 8-hour ozone nonattainment. 

Each State covered by CAIR may 

independently determine which 

emission sources to control, and which 

control measures to adopt. Our analysis 

indicates that emissions reductions from 

EGUs are highly cost effective, and we 

encourage States to base their CAIR SIP 

programs on emissions reductions from 

EGUs. States that do so may allow their 

EGUs to participate in an EPAadministered cap-and-trade program as 

a way to reduce the cost of compliance, 

and to provide compliance flexibility. 

The EPA-administered cap-and-trade 

program includes fossil-fuel fired 

boilers, combustion turbines, and 

certain cogeneration units with 

nameplate capacity of more than 25 

MWe producing or supplying electricity 

for sale as defined in 40 CFR 96.104 and 

96.204.6 Some of these units have never 

been subject to major NSR because they 

commenced construction before the 

effective date of the major NSR 

regulations, and they have never 

undertaken modifications. CAIR Units 

must hold annual allowances. Each 

allowance authorizes the emission of 

one ton of NOX for a specified calendar 

year. For SO2 allowances with vintage 

in the years before 2010, each allowance 

authorizes the emission of one ton of 

SO2 for a calendar year. For 2010 and 

beyond, each allowance authorizes the 

emission of less than one ton of SO2 per 

year.7 The CAIR emissions reductions 

will be implemented in two phases, one 

beginning in 2009 (2010 for SO2) and a 

second beginning in 2015. CAIR Units 

are subject to stringent monitoring, 

recordkeeping, and reporting 

requirements. Owner/operators must 

monitor and report CAIR Unit emissions 

using CEMS or other monitoring 

methodologies that are as precise, 

reliable, accurate, and timely according 

to the requirements in 40 CFR part 75. 

Source information management, 

emissions data reporting, and allowance 

trading occur through EPA-administered 

Federal Register / Vol. 70, No. 202 / Thursday, October 20, 2005 / Proposed Rules 61085 

8For a complete description of requirements for 

CAIR Units under the EPA-administered trading 

program, see item 0019 in E-Docket OAR–2005–

0163–70 FR 25162. 

9See our Regulatory Impact Analysis for the CAIR 

at 6–9. The RIA is available at http://www.epa.gov/ 

air/interstateairquality/pdfs/finaltech08.pdf. See 

item 0022 in E-Docket OAR–2005–0163. 

10These data are from EPA’s most recent 

Integrated Planning Model (IPM) modeling 

reflecting the final CAIR as promulgated at 70 FR 

25162. Please see the final CAIR rule at 70 FR 

25162. (See item 0019 in E-Docket OAR–2005–

0163) for a complete description of the assumptions 

related to these data. 11The banking provisions of the cap-and-trade 

program encourage sources to make significant 

reductions before 2010. Such early reductions are 

beneficial because they encourage greater health 

benefit sooner. However, due to the use of banked 

allowances, EPA does not project that these caps 

will be met in 2010 and 2015. 

12See item 0019 in E-Docket OAR–2005–0163—

70 FR 25162. 

13U.S. EPA, Regulatory Impact Analysis for the 

CAIR at p. 7–5. See item 0022 in E-Docket OAR–

2005–0163. Available at http://www.epa.gov/air/ 

interstateairquality/pdfs/finaltech08.pdf. For more 

information about the highly cost effective controls 

for EGUs that were used to establish the emissions 

reductions under the CAIR, see also 69 FR 4612 

(item 0003 in E-Docket OAR–2005–0163). 

14See CAIR RIA at 7–8 and 7–9 (item 0022 in EDocket OAR–2005–0163). The CAIR RIA is also 

available at http://www.epa.gov/air/ 

interstateairquality/technical.html. In 1999, total 

electric generating capacity was 781 GW, of which 

utilities accounted for approximately 85 percent. 

U.S. EPA NSR 90-Day Review Background Paper, p. 

12. See item 0039 in E-Docket OAR–2005–0163. 

online systems. Any source found to 

have excess emissions must surrender 

allowances sufficient to offset excess 

emissions and surrender future 

allowances equal to three times the 

excess emissions.8

The CAIR will result in significant 

reductions in SO2 and NOX emissions 

across the region that it covers. CAIR, if 

implemented through controls on EGUs, 

would result in EGU emissions 

reductions in the CAIR States of roughly 

73 percent for SO2 and 61 percent for 

NOX from 2003 levels. The rule would 

affect roughly 3,000 fossil-fuel-fired 

units. As Table 1 shows, these sources 

accounted for roughly 89 percent of 

nationwide SO2 emissions and 79 

percent of nationwide NOX emissions 

from EGUs in 2003.9

TABLE 1.—EGU SO2 AND NOX EMISSIONS IN 2003 AND PERCENTAGE OF EMISSIONS IN THE CAIR AFFECTED REGION

(TONS) 

SO2 NOX

CAIR region ............................................................................................................................................................. 9,407,406 3,222,636 

Nationwide ............................................................................................................................................................... 10,595,069 4,165,026 

CAIR emissions as % nationwide ........................................................................................................................... 89% 79% 

Note: Region includes States covered for the annual SO2 and NOX trading programs (Alabama, District of Columbia, Florida, Georgia, Illinois, 

Indiana, Iowa, Kentucky, Louisiana, Maryland, Michigan, Minnesota, Mississippi, Missouri, New York, North Carolina, Ohio, Pennsylvania, South 

Carolina, Tennessee, Texas, Virginia, West Virginia, and Wisconsin). 

We estimate that the CAIR will reduce 

SO2 emissions by 3.5 million tons 10 in 

2010 and by 3.8 million tons in 2015. 

We also estimate that it will reduce 

annual NOX emissions by 1.2 million 

tons in 2009 and by 1.5 million tons in 

2015. (These numbers are for the 23 

States and the District of Columbia that 

are affected by the annual SO2 and NOX

requirements of CAIR. There are 28 

States affected by CAIR, but only 23 

States affected by the CAIR annual SO2

and NOX requirements. That is, five 

States are only affected by the CAIR 

seasonal NOX trading program 

requirements.) If all the affected States 

choose to achieve these reductions 

through EGU controls, then EGU SO2

emissions in the affected States would 

be capped at 3.6 million tons in 2010 

and 2.5 million tons in 2015,11 and EGU 

annual NOX emissions would be capped 

at 1.5 million tons in 2009 and 1.3 

million tons in 2015. 

The CAIR will also improve air 

quality in all areas of the eastern U.S. 

We estimate that the required SO2 and 

NOX emissions reductions will, by 

themselves, bring into attainment 52 of 

the 79 counties that are otherwise 

projected to be in nonattainment for 

PM2.5 in 2010, and 57 of the 74 counties 

that are otherwise projected to be in 

nonattainment for PM2.5 in 2015. We 

further estimate that the required NOX

emissions reductions will, by 

themselves, bring into attainment three 

of the 40 counties that are otherwise 

projected to be in nonattainment for 8- 

hour ozone in 2010, and six of the 22 

counties that are otherwise projected to 

be in nonattainment for 8-hour ozone in 

2015.12 In addition, the CAIR will 

improve PM2.5 and 8-hour ozone air 

quality in the areas that would remain 

nonattainment for those two NAAQS 

after implementation of the rule. The 

CAIR will also reduce PM2.5 and 8-hour 

ozone levels in attainment areas. 

To determine the statewide emission 

caps under the CAIR, we assumed the 

application of highly cost-effective 

control measures to EGUs and 

determined the emissions reductions 

that would result. Specifically, we 

modeled emissions reductions using the 

Integrated Planning Model (IPM) with 

wet and dry desulfurization (FGD, 

commonly known as scrubbers) 

technologies for SO2 control and SCR 

technology for NOX control on coal-fired 

boilers.13 These are fully demonstrated 

and available pollution control 

technologies. The design and 

performance levels for these 

technologies were based on proven 

industry experience. 

We expect many EGUs to install 

scrubbers and SCR to meet the 

emissions reductions required under the 

CAIR. As a result of the CAIR, we 

project installation of scrubbers on an 

additional 64 GW of existing coal-fired 

generation capacity for SO2 control and 

SCR on an additional 34 GW of existing 

coal-fired generation capacity for NOX

control by 2015. By 2020, we expect 

installation of scrubbers on an 

additional 82 GW of existing coal-fired 

generation capacity for SO2 control and 

SCR on an additional 33 GW of existing 

coal-fired generation capacity for NOX

control.14

In the western half of the U.S. and 

other States where CAIR will not apply, 

the Best Available Retrofit Technology 

(BART) requirements of the regional 

haze rule will also apply to EGUs that 

may not be subject to major NSR. The 

regional haze rule requires all States to 

take steps in their implementation plans 

to improve visibility in Class I areas. [64 

FR 35714 (July 1, 1999); 70 FR 39104 

(July 6, 2005)] Under the Regional Haze 

program, States are to address all types 

of manmade emissions contributing to 

visibility impairment in Class I areas, 

including those from mobile sources, 

stationary sources (such as EGUs), area 

sources such as residential wood 

combustion and gas stations, and 

prescribed fires. CAA sections 

169(b)(2)(A) and (g)(7) specifically 

require installation of BART for 

emissions of visibility-impairing 

pollutants (for example, SO2 and NOX) 

from certain existing stationary sources, 

including large EGUs. The CAA defines 

61086 Federal Register / Vol. 70, No. 202 / Thursday, October 20, 2005 / Proposed Rules 

15See Federal Register 70 FR 39104 (July 6, 2005) 

at item 0017 in E-Docket OAR–2005–0163. 

16That is, these are the reductions that are 

estimated to occur under Scenario 2 in addition to 

the reductions that are estimated to occur under 

CAIR. See BART RIA at 3–6—item 0004 in E-Docket 

OAR–2005–0163. Regulatory Impact Analysis for 

the Final Clean Air Visibility Rule or the Guidelines 

for Best Available Retrofit Technology (BART) 

Determinations Under the Regional Haze 

Regulations. EPA–452/R–05–004. U.S. 

Environmental Protection Agency, June 2005. Also, 

available at: http://www.epa.gov/oar/visibility/ 

actions.html. 

17Major stationary sources of regulated NSR 

pollutants that commenced construction on or after 

August 7, 1977 are subject to requirements under 

major NSR, including meeting emissions limitations 

based on BACT or LAER. To be BART-eligible, an 

EGU must have commenced operation between 

August 7, 1962 and August 7, 1977. Thus, due to 

their construction date, BART-eligible EGUs are not 

subject to major NSR unless they modify. 

18 Information received from Mikhail 

Adamantiades, U.S. EPA, Clear Air Markets 

Division on October 4, 2005—item 0051 in E-Docket 

OAR–2005–0163. 

19We expect all State agencies to include EGUs 

in their regulations implementing the CAIR rule. 

We therefore believe that in CAIR-affected States, 

regulations implementing the CAIR will apply to all 

EGU. However, there is a possibility that a State 

agency would decide not to include EGU in their 

SIP regulations implementing the CAIR. We believe 

this possibility to be remote. 

a BART-eligible source as a stationary 

source of air pollutants that falls within 

one of 26 listed categories and that was 

put into operation between August 7, 

1962 and August 7, 1977, with the 

potential to emit 250 tons per year of 

any visibility-impairing pollutant. [CAA 

section 169(b)(2)(A) and (g)(7); 40 CFR 

51.301.] 

We issued guidelines for 

implementing BART requirements,15

including presumptive BART control 

levels for emissions of SO2 and NOX

from utility boilers located at power 

plants over 750 MW. Those presumptive 

BART control levels are based on cost 

effective controls. As explained in the 

guidelines, as a general matter States 

must require owners and operators of 

greater than 750 MW power plants to 

meet these BART emission limits. In 

addition, while States are not required 

to follow these guidelines for EGUs 

located at power plants with a 

generating capacity of less than 750 

MW, based on our analysis, we believe 

that States will find these same 

presumptive controls to be highly cost 

effective, and to result in a significant 

degree of visibility improvement, for 

most EGUs greater than 200 MW, 

regardless of the size of the plant at 

which they are located. 

Regional haze is the result of air 

pollutants emitted by numerous sources 

over a wide geographic region. As a 

result, EPA has encouraged States to 

work together in developing and 

implementing their air quality plans 

addressing regional haze. In fact, the 

States have been working together in 

regional planning organizations to 

develop regional plans. Moreover, we 

have proposed a process by which 

States may use an emissions trading 

program in place of facility-by-facility 

BART requirements. In these aspects, 

the requirements for BART are similar 

to those under the CAIR. We expect that 

both the CAIR and the BART 

requirements will reduce regional SO2

and NOX emissions from EGUs in a costeffective manner. 

We developed three scenarios to 

project the nationwide EGU SO2 and 

NOX emissions reductions under BART. 

Under the medium stringency scenario 

(Scenario 2), we estimate that BART 

controls will result in annual NOX

reductions of 585,459 tons, about a 9.6 

percent reduction; and in annual SO2

reductions of 390,224 tons, about a 2.3 

percent reduction, over the 2015 base 

case.16 Under Scenario 2, BART is 

projected to result in the installation of 

scrubbers on an additional 6.2 GW of 

existing coal-fired generation capacity 

for SO2 control in 2015 (relative to 

expected reductions from CAIR alone). 

For NOX control, this BART scenario is 

also projected to result in installation of 

combustion control equipment on an 

additional 24 GW of coal-fired 

generation capacity by 2015, as well as 

installation of SCR on an additional 2.4 

GW on coal-fired generation capacity by 

2015. 

We have conducted analyses based on 

emission projections and air quality 

modeling showing that CAIR (as we 

expect States to implement it) will 

achieve greater reasonable progress 

towards the national visibility goal than 

would BART for affected EGUs. In our 

final BART rule (70 FR 39104), we thus 

promulgated regional haze rule 

revisions allowing States to treat CAIR 

as an in-lieu-of BART program for SO2

and NOX emissions from EGUs in CAIRaffected States, where those States 

participate in the EPA-administered cap 

and trade program. The criteria for 

making ‘‘better than BART’’

determinations have now been codified 

in the regional haze rule at 40 CFR 

51.308(e)(3). We thus expect EGUs in 

CAIR-affected States to be subject to 

SIPs implementing CAIR SO2 and NOX

requirements rather than to BART. 

We are aware that there are some 

EGUs that would not be subject to the 

Acid Rain program or BART, would not 

be included in the CAIR program due to 

their geographic location, and that also 

would not be subject to major NSR 

unless they choose to modify.17 First, 

there is a set of EGUs that are not in 

CAIR affected States, and that are 

BART-eligible but may not be subject to 

BART. Assuming Scenario 2, there 

would be approximately 28 coal-fired 

EGUs that are BART-eligible, not in the 

CAIR region, and have a capacity less 

than 200 MW. Smaller units such as 

these generally are not base load units. 

The total capacity for these 28 units is 

approximately 4 GW, less than one half 

of a percent of current national capacity. 

Of these 28 units, approximately 3 GW 

have NOX controls and approximately 2 

GW have SO2 controls. There are 

approximately 47 oil or gas-fired EGUs 

that are BART-eligible, not in the CAIR 

region, and have a capacity less than 

200 MW. The total capacity for these 47 

units is approximately 5 GW, also less 

than one half of a percent of national 

capacity. Of these 47 units, 

approximately 1 GW have NOX controls. 

Of these 47 units, 41 are gas-fired. Gasfired EGU are clean burning and 

generally emit very small amounts of 

SO2. The main control strategy for SO2

emissions from oil-fired units is using 

lower-sulfur fuel. 

The second set of EGUs that may not 

be subject to any control requirements 

are those in the non-CAIR States that are 

not subject to major NSR and are not 

BART-eligible. Some EGUs that are 

located in non-CAIR States and that 

began operation on or before August 7, 

1962 would not be BART-eligible. These 

units would neither be subject to BART 

nor included in regulations 

implementing the CAIR program. They 

would also not be subject to major NSR 

unless they choose to modify. Some 

may be subject to the Acid Rain 

program. Our database 18 shows that 

there is a total of about 2 GW of coal 

capacity (less than one half of a percent 

of national capacity) outside the CAIR 

region that was constructed or began 

operations before 1962. This capacity 

represents about 25 units at about 13 

plants, ranging in capacity from 38–135 

MW. Smaller, older units such as these 

generally are not base load units. We 

estimate that these units have a 

potential to emit SO2 and NOX that is 

high enough that they would have been 

subject to major NSR if they had been 

constructed later. Of these 25 units, four 

have NOX controls and six have SO2

controls. The 13 plants are 

geographically dispersed. 

Thus, as we explain above, there are 

a small number of EGUs that may not 

be required to control emissions under 

any program, but they comprise a very 

small portion of the national capacity 

and will have a minimal impact on 

emissions.19 As we note in Table 1, 

Federal Register / Vol. 70, No. 202 / Thursday, October 20, 2005 / Proposed Rules 61087 

20Modeled 1990 baseline emissions from John 

Robbins. Reductions based on 2015 projected 

emissions for EGUs greater than 25 MW, assuming 

BART Scenario 2 (medium stringency scenario). 

These projected reductions assume control 

requirements implemented under CAIR, the Acid 

Rain program, BART (Scenario 2), and State rules. 

Under BART Scenario, our IPM modeling assumes 

control of all EGU at least 200 MW, regardless of 

the size of the plant at which the EGU is located. 

See BART RIA at 7–7—item 0004 in E-Docket OAR–

2005–0163. 

21 Data from EPA Office of Air and Radiation, 

Clean Air Markets Division. See item 0012 in EDocket OAR–2005–0163. 

approximately 90 percent of nationwide 

EGU SO2 emissions and approximately 

80 percent of nationwide EGU NOX

emissions are from EGU in the CAIR 

affected region. Furthermore, we note 

that EGUs, including EGUs outside the 

CAIR region, are subject to national caps 

on SO2 emissions through the Acid Rain 

program requirements. We therefore 

believe that any EGUs that might remain 

uncontrolled would have a negligible 

impact on national emissions of 

regulated NSR pollutants. 

Finally, as Table 2 below shows, 

substantial reductions in SO2 and NOX

emissions are projected to occur 

following the imposition of these 

market-based strategies after 1990. 

TABLE 2.—REDUCTION IN EGU NATIONAL ANNUAL EMISSIONS 20

[In thousands of tons per year] 

1990 2015 Emission 

reduction 

Percent 

reduction 

SO2 (Annual) .................................................................................................................... 15,700 4,770 10,930 70 

NOX (Annual) ................................................................................................................... 6,700 1,916 4,784 71 

The figure below shows the national 

reductions in EGU SO2 and NOX

emissions that have occurred to date, 

and that we expect to occur, due to 

these programs. 

These reductions in national 

emissions for the utility sector are 

especially significant considering that 

national capacity continues to increase. 

In 1990, national nameplate capacity for 

EGUs was 692,935 MW, in 2002 it was 

758,756 MW, and in 2015 we anticipate 

it to be 776,377 MW.21

In summary, since the 1990 CAA 

Amendments, additional requirements 

for EGUs have applied under the Acid 

Rain program and the NOX SIP Call, and 

we expect significant additional 

reductions as States implement the 

CAIR. These regional and national 

programs apply or will apply to EGUs, 

regardless of when the EGUs were 

constructed or began operating. More 

importantly, these national or regional 

trading programs set permanent caps on 

SO2 and NOX emissions. Notably, the 

CAIR will permanently cap SO2 and 

NOX emissions in the CAIR region, 

which covers approximately 80 percent 

of national electric generating capacity. 

We expect all of the SO2 and NOX

reductions under CAIR to come from 

EGUs. Despite growth in the utility and 

other sectors, these programs have 

substantially reduced SO2 and NOX

emissions and even more substantial 

reductions will occur as a result of the 

CAIR. The BART program will further 

reduce national EGU SO2 and NOX

emissions. 


EP20OC05.008</GPH>
61088 Federal Register / Vol. 70, No. 202 / Thursday, October 20, 2005 / Proposed Rules 

22 In our projections of emissions changes under 

the Acid Rain program, the NOX SIP Call, the CAIR, 

and BART, increases in future electric generating 

capacity are accounted for. 

23See information received from Kevin Culligan, 

U.S. EPA Clean Air Markets Division, item 0044 in 

E-Docket OAR–2005–0163. 

24We described the relationship between the 

provisions contained in sections 60.2 and 60.14 in 

a 1974 Federal Register notice in which we stated 

that the regulations concerning modifications in 

§ 60.14 clarify the phrase ‘‘increases the amount of 

any air pollutant’’ that appears in the definition of 

modification in § 60.2. 39 FR 36946, October 15, 

1974—see item 0014 in E-Docket OAR–2005–0163. 

The Acid Rain, NOX SIP Call and 

CAIR programs will require substantial 

reductions in SO2 and NOX emissions 

over the next decade. At the same time, 

they provide substantial flexibility to 

EGUs in responding to these regulatory 

requirements, allowing EGUs to make 

cost effective control decisions. As a 

result, they serve a function similar to 

that under major NSR of balancing 

environmental goals and encouraging 

economic growth. 

As we discuss in more detail in 

Section V.B. of this preamble, the 

primary purpose of the major NSR 

program is not to reduce emissions, but 

to balance the need for environmental 

protection and economic growth. That 

is, the goal of major NSR is to minimize 

emissions increases from new source 

growth. The major NSR approach we 

have been taking leads to outcomes that 

have not advanced the central policy of 

the major NSR program as applied to 

existing sources. This is because the 

program is not designed to cut back on 

emissions from existing major stationary 

sources through limitations on their 

productive capacity, but rather to ensure 

that they will install state-of-the-art 

pollution controls at a juncture where it 

otherwise makes sense to do so. We also 

do not believe the outcomes produced 

by the approach we have been taking 

have significant environmental benefits 

compared with the approach we are 

proposing today. We do not believe that 

today’s revised emissions test is 

substantially different from the actualto-projected-actual test. This is 

particularly true in light of the 

substantial EGU emissions reductions 

that other programs have achieved or 

are expected to achieve. We therefore 

believe that, to any extent today’s 

revised emissions test would lead to 

more growth in emissions than the 

actual-to-projected-actual test would, 

the emissions increases from that 

growth would be substantially less than 

the emissions reductions we expect 

from the Acid Rain, NOX SIP Call, CAIR, 

and BART programs.22

C. Requirements for Pollutants Other 

Than SO2 and NOX

Concerning PM and lead, the 

application of the major NSR program to 

EGU emissions increases would be 

unlikely to result in the implementation 

of any additional controls. Current 

BACT and LAER limits to control PM 

(both PM10 and PM2.5) for EGUs are 

achieved through the application of 

baghouses or electrostatic precipitators 

(ESPs) to individual boilers. Of the 450 

coal-fired plants, the following controls 

are in place to reduce PM emissions 

from EGU: 79 plants have bag houses 

(fabric filters), 354 plants have ESPs, 

and 21 plants have both ESPs and 

baghouses.23 Therefore, virtually all 

coal-fired EGUs are already wellcontrolled for PM. The minimal lead 

emissions from EGUs are in particulate 

form, and are captured by PM controls. 

For CO and VOC, the only BACT/ 

LAER requirements that exist for boilers 

are ‘‘good combustion’’ practices. EGUs 

operate under enormous economic 

incentives not to waste fuel, and good 

combustion practices conserve fuel. 

Thus, EGUs have strong incentives to 

use good combustion practices, 

regardless of the major NSR regulations. 

We believe that virtually all EGUs are 

already implementing such practices to 

control CO and VOC. Accordingly, we 

do not believe that VOC or CO 

emissions increases at EGU are likely or 

that the application of the major NSR 

program to changes made at the EGUs 

would be likely to result in the 

implementation of additional controls 

for CO and VOC. Furthermore, even if 

EGU did not have built-in incentives to 

control VOC and CO emissions, we do 

not believe that today’s revised 

emissions test would result in emissions 

increases compared to the actual-toprojected-actual test. Therefore, we 

expect no air quality impacts due to CO 

or VOC emissions as a result of this 

proposed rule. 

IV. Today’s Proposed Rule 

Today, we are proposing to allow 

existing EGUs to use the same 

maximum achievable hourly emissions 

test we apply under NSPS to determine 

whether a physical change in or change 

in the method of operation (physical or 

operation change) results in an 

emissions increase under the major NSR 

program. We request public comments 

on all aspects of the proposed changes. 

This section also provides a brief 

background on the emissions increase 

test used in the NSPS and major NSR 

programs, and summarizes our 

proposed changes to the NSR program, 

which is necessary to understand the 

proposed regulations. For a fuller 

discussion on the statutory and 

legislative background of the major NSR 

program, please see Section V.B. of 

today’s preamble. 

A. Background on Existing Regulations 

Both the NSPS and major NSR 

programs impose requirements on 

modifications of stationary sources. Our 

NSPS regulations contain a two-part 

definition of modification. The first part 

substantially mirrors the statutory text 

found in section 111(a)(4) of the Act, 

while the second elaborates upon the 

first. In simplistic terms, the Act 

establishes a two-step test for 

determining whether an activity is a 

modification. First you must determine 

whether the activity qualifies as a 

physical change or operational change 

of a stationary source, then you must 

determine whether that activity also 

increases the amount of pollution 

emitted by the stationary source. 

You can find the regulatory text 

defining ‘‘modification’’ within the 

NSPS general provision regulations at 

40 CFR sections 60.2 and 60.14. 

Substantially mirroring CAA 111(a)(4), 

§ 60.2 contains a general description of 

the two components an activity must 

satisfy to qualify as a modification. 

Section 60.14 elaborates on the general 

description contained in § 60.2 by more 

precisely defining how you measure the 

amount of pollution that results from an 

activity, and listing activities that do not 

qualify as physical or operational 

changes.24

Unlike our NSPS regulations, our 

major NSR regulations do not contain a 

specific definition of the term 

‘‘modification.’’ Instead, our regulations 

define ‘‘major modification,’’ which 

adds provisions for determining 

whether an activity satisfies the second 

component (whether there is an increase 

in the amount of an air pollutant). 

Specifically, the major modification 

definition provides a two-step 

procedure for measuring emissions 

increases. Under this process, a source 

looks at whether a project will result in 

a significant emissions increase on an 

annual basis and then whether 

contemporaneous increases and 

decreases will result in a significant net 

emissions increase (netting) on an 

annual basis. 

The differences between the 

definition of ‘‘modification’’ as applied 

in the NSPS program and ‘‘major 

modification’’ as applied in the major 

NSR program illustrate some 

fundamental differences in the way we 

have implemented the programs to date. 

Federal Register / Vol. 70, No. 202 / Thursday, October 20, 2005 / Proposed Rules 61089 

25These changes were adopted on December 16, 

1975 (see 40 FR 58416) and the provisions have 

remained unchanged, except to clarify that they 

apply to the facility rather than to the stationary 

source containing that facility. 

26The legislative history is clear that Congress 

considered ‘‘potential to emit’’ and ‘‘design 

capacity’’ to be equivalent terms. The House bill 

defined a major stationary source as any stationary 

source of air pollutant which directly emits or has 

the design capacity to emit 100 tons annually of any 

pollutant for which an ambient air quality standard 

is promulgated. [H.R. Report 95–564, p. 172 (1977), 

U.S. Code Cong. & Admin.News 1977, p. 1552.] The 

House bill also stated that ‘‘major emitting facilities 

proposing to construct facilities must receive State 

permits. All sources with the design capacity to 

emit 100 tons per year or more of any pollutant 

must receive a permit.’’ [H.R. Report 95–564, p. 149 

(1977), U.S. Code Cong. & Admin.News 1977, p. 

1529.] The Senate amendment defined major 

emitting facility as any stationary source with an 

annual potential to emit 100 tons or more of any 

pollutant. The Senate bill also required permits for 

major stationary sources with potential to emit over 

250 tons per year. The conference committee agreed 

on the provisions on major emitting facilities and 

major stationary sources to be included in the 

statute at 302(j) and 169(1) as follows. 

The State plan must require permits for: (a) All 

28 categories listed in the Senate bill if the sources 

has the potential (design capacity) to emit over 100 

tons per year; and (b) any other source with the 

design capacity to emit more than 250 tons per year 

of any air pollutant. [H.R. Report 95–564, p. 149 

(1977), U.S. Code Cong. & Admin.News 1977, p. 

1153]. 

27Memorandum dated September 9, 1988, from 

Don R. Clay, Acting Assistant Administrator for Air 

& Radiation, U.S. EPA, to David A. Kee, Director, 

Air and Radiation Division, U.S. EPA Region V. 

Applicability of PSD and NSPS Requirements to the 

WEPCO Port Washington Life Extension Project. 

Available at: http://www.epa.gov/region7/programs/ 

artd/air/nsr/nsrmemos/wpco2.pdf. Page 9 and item 

0005 in E-Docket OAR–2005–0163. 

First, the NSPS program regulates all 

emissions increases (that is, it regulates 

any increase in the hourly emissions), 

while the major NSR program exempts 

emissions increases that are less than 

significant (that is, it exempts emissions 

increases that are less than 40 tpy). 

Second, the NSPS program regulates 

modifications of ‘‘affected facilities,’’

which are typically small collections of 

equipment within a larger 

manufacturing plant. The major NSR 

program regulates modifications of 

major stationary sources. Accordingly, 

all the equipment within a larger 

manufacturing plant is looked at 

collectively. Finally, because the NSPS 

regulates small collections of equipment 

rather than the entire plant, increases in 

one part of the plant cannot be ‘‘offset’’

with decreases at other parts of the 

plant. [See Asarco, Inc. v. EPA, 578 F.2d 

319 (D.C. Cir. 1978).] Conversely, major 

NSR regulates changes in emissions at 

the major stationary source as a whole 

and allows decreases in emissions from 

one part of the plant to ‘‘offset’’

increases in emissions that occur in 

another part of the plant. [See Alabama 

Power v. Costle, 636 F.2d 323 (D.C. Cir. 

1979).] This process is known as 

‘‘netting.’’

The NSPS modification provisions 

apply an hourly emission rate test to 

measure emissions increases resulting 

from a physical or operational change. 

Specifically, under the regulations, 

whether there is an emissions increase 

is determined by comparing the prechange baseline hourly emission rate to 

the post-change hourly emission rate. 

For electric utility steam generating 

units (EUSGUs), the baseline hourly rate 

is ‘‘the maximum hourly emissions 

achievable at that unit during the 5 

years prior to the change.’’ [See 40 CFR 

60.14(h).] EPA has described this rate as 

the rate, in the past 5 years, that the 

source could achieve at its physical and 

operational capacity (57 FR 32330). 

Thus, this hourly rate represents the 

highest rate at which the source could 

actually emit during the relevant period. 

The baseline hourly emissions rate for 

non-EGUs is likewise based on current 

maximum capacity, which is defined as 

the production rate at which the source 

could operate without making a capital 

expenditure. [See § 60.14(e)(2).] As 

provided in § 60.14 (b)(1), we measure 

the emissions rate in kg/hr or lbs/hr. 

Therefore, the baseline hourly emissions 

for non-utilities is also based on the 

highest rate at which the source could 

actually emit. As we stated at 57 FR 

32316 referring to the rules for nonutilities, ‘‘under current NSPS 

regulations, emissions increases, for 

applicability purposes, are calculated by 

comparing the hourly emission rate, at 

maximum physical capacity, before and 

after the physical or operational change. 

That is, to determine whether a change 

to an existing facility will increase the 

emissions rate, the existing NSPS 

regulations authorize the use of an 

‘‘emissions factor analysis’’, or materials 

balance, continuous monitoring, or 

manual emissions test to evaluate 

emissions before and after the change.’’

This characterization of the emissions 

rate as based on the highest rate at 

which the source could actually emit is 

consistent with our previous statements 

and regulations. In the preamble to the 

December 23, 1971 NSPS rules, we 

stated that ‘‘procedures have been 

modified so that the equipment will 

have to be operated at maximum 

expected production rate, rather than 

rated capacity, during compliance 

tests.’’ (See 36 FR 24876.) The December 

1971 rules specified that a change in the 

method of operation did not include ‘‘an 

increase in the production rate, if such 

increase does not exceed the operating 

design capacity of the affected facility.’’

(See 36 FR 24877.) On October 15, 1974, 

we proposed to change this provision to 

‘‘an increase in the production rate of an 

existing facility, if that increase can be 

accomplished without a major capital 

expenditure’’ and to move it to 

§ 60.14(e)(2).25 [See 39 FR 36946.] In 

describing the reason for this change, 

we specifically stated that hourly 

emissions must be determined 

considering what the source could 

actually emit, rather than ‘‘design’’

(nameplate) capacity. 

The exemption of increases in production 

rate is no longer dependent upon the 

‘‘operating design capacity.’’ This term is not 

easily defined and for certain industries the 

‘‘design capacity’’ bears little relationship to 

the actual operating capacity of the facility. 

Id. at 39 FR 36948. 

As Congress indicated in the 

legislative history for the 1977 CAA,26

design capacity is equivalent to 

potential to emit. In the NSPS 

regulations, neither the EGU nor the 

non-EGU hourly emissions are based on 

design capacity. Thus, to describe the 

NSPS test as a potential-to-potential test 

is inaccurate, and EPA has not asserted 

that the NSPS test is a potential-topotential test. Instead, the Agency has at 

times referred to ‘‘hourly potential 

emissions.’’ Where we have referred to 

hourly potential emissions, we have 

also been clear that we are referring to 

what the source is actually able to emit 

at current maximum capacity. For 

example, in the 1988 WEPCO 

memorandum, we stated: 

Pursuant to longstanding EPA 

interpretations, the emission rate before and 

after a physical or operational change is 

evaluated at each unit by comparing the 

hourly potential emissions under current 

maximum capacity to emissions at maximum 

capacity after the change.’’ 27

Our current major NSR regulations 

measure an emissions increase at an 

existing emissions unit using the 

‘‘actual-to-projected-actual’’

applicability test. Under this approach, 

we compare an emissions unit’s 

‘‘baseline actual emissions’’ to the 

emission unit’s projected actual 

emissions after the change. Our current 

test distinguishes how non-EUSGUs 

compute an emissions unit’s baseline 

actual emissions from the method used 

for EUSGUs. We define baseline actual 

emissions for non-EUSGUs as the 

average annual emission rate calculated 

from any consecutive 24-month period 

in the past 10 years. For EUSGUs, the 

baseline actual emissions equals the 

average annual emission rate achieved 

over any consecutive 24-month period 

in the past 5 years unless there is 

another period of time that is more 

representative of normal source 

61090 Federal Register / Vol. 70, No. 202 / Thursday, October 20, 2005 / Proposed Rules 

28On August 25, 2005, we proposed regulatory 

language to clarify that the definition of EGU in 

CAIR does not include municipal waste combustors 

or solid waste incinerators, and to clarify that the 

definition only covers entities that have at any time 

since November 15, 1990 served an electric 

generator with a nameplate capacity greater than 25 

megawatts (MW) producing electricity for sale. See 

70 FR 49708, item 0029 in E-Docket OAR–2005–

0163. 

29 In the near future, we plan to publish a 

proposed rule addressing NSR requirements in 

tribal lands. 

30The major NSR regulations define NSR 

regulated pollutants at 40 CFR 51.166(b)(49). 

31The Duke Energy Court also noted that in 

Northern Plains Res. Council v. EPA, 645 F.2d 1349, 

1356 (9th Cir. 1981) [see item 0046 in E-Docket 

OAR–2005–0163], the Ninth Circuit allowed EPA to 

interpret the statutory term ‘‘commenced’’

differently in the NSPS and PSD regulations. Duke 

Energy, slip op. at 17. 

operations. We use the same definition 

of projected actual emissions for both 

EUSGUs and non-EUSGUs. The rules 

generally define projected actual 

emissions as the maximum annual rate 

of emissions at which the emissions 

unit is projected to operate for the first 

5 years after the emissions unit begins 

operation following the change. See 40 

CFR 51.166 (b)(47) and (b)(40) to 

understand all aspects of the baseline 

actual emissions and projected actual 

emissions definitions. 

B. What We Are Proposing 

1. Test for EGUs Based on Maximum 

Achievable Hourly Emissions 

Today, we are proposing to allow 

existing EGUs to use the same 

maximum achievable hourly emissions 

test applied in the NSPS to determine 

whether a physical or operation change 

results in an emissions increase under 

the major NSR program. Accordingly, 

the major NSR regulations would apply 

at an EGU if a physical or operational 

change results in any increase in the 

maximum hourly emissions rate. We are 

not proposing to allow EGUs to exclude 

emissions increases that fall below a 

particular significant emissions rate, or 

to allow EGUs to use plantwide netting 

to avoid NSR applicability. 

We are proposing to define EGUs in 

the same way that this term is defined 

by the CAIR and Acid Rain regulations. 

Specifically, we would define EGU as 

fossil-fuel fired boilers and turbines 

serving an electric generator with a 

nameplate capacity greater than 25 

megawatts (MW) producing electricity 

for sale.28 Fossil fuel is described as 

natural gas, petroleum, coal, or any form 

of solid, liquid, or gaseous fuel derived 

from such material. The term ‘‘fossil 

fuel-fired’’ with regard to an emissions 

unit means combusting fossil fuel, alone 

or in combination with any amount of 

other fuel or material. 

This definition of EGU is broader than 

the definition of EUSGU currently 

found in the NSPS and NSR regulations. 

The EGU definition includes 

cogeneration facilities and simple cycle 

gas turbines that would not qualify 

under EUSGU definitions. That is, the 

revised emissions test would apply to 

EUSGUs, cogeneration facilities, and 

simple cycle gas turbines. 

To incorporate the NSPS maximum 

achievable hourly emissions test into 

the major NSR regulations, we are 

proposing to add a definition of 

modification to the major NSR 

regulation that will apply to changes 

affecting regulated NSR pollutant 

emissions in lieu of the current 

definition of major modification. We 

would add the new definition to all 

versions of the NSR regulations 

including 40 CFR 51.165, 51.166, 52.21, 

52.24, and in Appendix S of 40 CFR part 

51, as well as any regulations we 

finalize to implement major NSR in 

Indian Country.29

We propose that this definition would 

substantially mirror, but would not be 

identical to, the definition of 

modification contained in section 60.14 

of the NSPS regulations. There are 

differences between the two programs 

that prevent a wholesale adoption of the 

NSPS modification definition into the 

major NSR provisions. For example, the 

NSPS program applies the definition of 

modifications only to stationary sources 

and pollutants for which a particular 

NSPS standard applies. Specifically, the 

NSPS program regulates modifications 

of ‘‘affected facilities,’’ which are 

typically small collections of equipment 

within a larger manufacturing plant. 

The NSPS program also specifies which 

pollutants from the affected facility are 

regulated. For example, Subpart Da of 

40 CFR part 60 regulates emissions 

increases of sulfur dioxides, nitrogen 

oxides, and particulate matter from 

EUSGUs. The major NSR program, on 

the other hand, regulates modifications 

of major stationary sources. 

Accordingly, all the equipment within a 

larger manufacturing plant is looked at 

collectively. Furthermore, the Act 

mandates that major NSR requirements 

apply to modifications at any major 

stationary source that increases 

emissions of any regulated NSR 

pollutant.30 The proposed definition is 

as follows. 

‘‘Modification,’’ for an electric generation 

unit (EGU), means any physical change in, or 

change in the method of operation of, an EGU 

which increases the amount of any regulated 

NSR pollutant emitted into the atmosphere 

by that source or which results in the 

emission of any regulated NSR pollutant(s) 

into the atmosphere that the source did not 

previously emit. An increase in the amount 

of regulated NSR pollutants must be 

determined according to the provisions in 

paragraph (x) of this section. 

We disagree with the Fourth Circuit’s 

holding in Duke Energy, and thus 

believe we are able to make reasonable 

distinctions between the NSPS and NSR 

programs where appropriate. Although 

the Fourth Circuit held in Duke Energy 

that we must use the same definition of 

modification in both the NSPS and NSR 

programs where appropriate, it only 

discussed this finding in the context of 

the component term of the definition 

‘‘increases in the amount of any air 

pollutant emitted.’’ In fact, the Court 

noted that the Fourth Circuit had 

previously held that the term 

‘‘stationary source,’’ a component term 

within the definition of ‘‘modification,’’

could be interpreted differently in the 

NSPS and PSD programs because 

Congress had not defined the term in 

both programs. [Duke Energy, slip op. at 

17, citing Potomac Elec. Power Co. v. 

EPA, 650 F.2d 509, 518 (4th Cir. 

1981).31 Accordingly, we believe it is 

reasonable to interpret the Duke Energy 

decision as requiring, within the Fourth 

Circuit, that the maximum hourly 

emissions test be used within the major 

NSR provisions, but as not requiring the 

identical treatment of the term 

‘‘physical change in or change in the 

method of operation.’’ Based on our 

interpretation, we propose to 

incorporate the part of the major 

modification definition that addresses 

regulation of physical and operational 

changes into the modification definition 

for EGUs. We request comment on this 

interpretation. 

We also are not proposing to change 

our current methodologies for 

computing the amount or availability of 

emissions offsets, or for computing 

emissions for purposes of conducting an 

ambient impact analysis. Accordingly, 

EGUs will be required to follow the 

existing regulations related to these 

provisions. 

In proposing this NSR test for EGUs 

based on maximum achievable hourly 

emissions, we are aware of the recent 

opinion by the United States Court of 

Appeals for the District of Columbia 

Circuit in New York v. EPA, 413 F.3d 3 

(D.C. Cir. June 24, 2005). In that case, 

the Court rejected challenges to 

substantial portions of EPA’s 2002 NSR 

rules. However, the Court did hold that 

EPA lacked authority to promulgate the 

‘‘Clean Unit’’ provision of the 2002 

rules, and in doing so, held that ‘‘the 

plain language of the CAA indicates that 

Federal Register / Vol. 70, No. 202 / Thursday, October 20, 2005 / Proposed Rules 61091 

32See also 36 FR 24876, December 23, 1971. 

Referring to performance tests, we stated that 

‘‘Procedures have been modified so that the 

equipment will have to be operated at maximum 

expected production rate, rather than rated 

capacity, during compliance tests. 

33See the EPA memorandum, Issuance of Final 

Clean Air Act National Stack Testing Guidance, 

from Michael M. Stahl, Director, Office of 

Compliance, to Regional Compliance/Enforcement 

Division Directors, September 30, 2005, p. 14. 

Available at http://www.epa.gov/Compliance/ 

resources/policies/monitoring/caa/stacktesting.pdf 

and item 0007 in E–Docket OAR–2005–0163. 

Congress intended to apply NSR to 

changes that increase actual emissions 

instead of potential or allowable 

emissions.’’ Id., slip op. at 40. 

We respectfully disagree with the 

Court’s holding that the plain language 

of the CAA requires that NSR apply to 

changes in actual emissions, and the 

United States has filed a petition for 

rehearing and rehearing en banc as to 

this holding. We believe that the CAA 

is silent on whether increases in 

emissions for purposes of determining 

whether a physical or operational 

change constitutes a modification must 

be measured in terms of actual 

emissions, potential emissions, or some 

other currency. Therefore, we believe 

that even if the test for emissions 

increases that we propose today were 

based on something other than actual 

emissions, it would be an appropriate 

interpretation and entitled to deference 

under step 2 of the analytical process set 

forth in Chevron U.S.A., Inc. v. Natural 

Res. Def. Council, 467 U.S. 837 (1984). 

Nonetheless, we recognize that we must 

promulgate a rule that is consistent with 

the D.C. Circuit’s resolution of this 

issue. 

Regardless of whether our petition for 

rehearing in New York v. EPA is denied, 

we believe that a test based on 

maximum achievable hourly emissions 

is a test based on actual emissions. The 

maximum achievable hourly emissions 

test measures what a source has been 

actually able to emit based on physical 

and operating capacity during a 

representative period prior to the 

change. For most, if not all EGUs, the 

hourly rate at which the unit is actually 

able to emit is substantively equivalent 

to that unit’s historical maximum 

hourly emissions. States require most, if 

not all EGUs, to perform periodic 

performance tests under applicable SIPs 

and enhanced monitoring requirements. 

The NSPS regulations require a source 

to conduct testing based on 

representative performance of the 

affected facility, generally interpreted as 

performance at current maximum 

physical and operational capacity. [40 

CFR 60.8(c).] 32 Also, in the National 

Stack Test Guidance that we issued on 

September 30, 2005, we recommended 

that facilities conduct performance tests 

under conditions that are ‘‘most likely 

to challenge the emissions control 

measures of the facility with regard to 

meeting the applicable emission 

standards, but without creating an 

unsafe condition.’’ 33 Most EGUs 

actually emit at the highest level at 

which they are capable of emitting at 

some time within a 5-year baseline 

period. 

We solicit comment on our 

assumption that an NSR test for EGUs 

based on maximum achievable hourly 

emissions is, in fact, a test that would 

be based on a measure of actual 

emissions in light of the manner in 

which EGUs are operated. 

As we noted earlier, the current major 

NSR regulations contain a definition of 

major modification. Specifically, the 

major modification definition provides a 

two-step procedure for measuring 

emissions increases. Under this process, 

a source looks at whether a project will 

result in a significant emissions increase 

on an annual basis and then whether 

contemporaneous increases and 

decreases will result in a significant net 

emissions increase (netting) on an 

annual basis. We are proposing to 

replace this definition of major 

modification with a definition of 

modification based on the maximum 

hourly achievable emissions increase 

test (or one of the two other emissions 

increase tests that we discuss in the 

following sections, maximum achieved 

emissions or an output-based measure 

of emissions). However, we request 

comment on whether we should instead 

add the definition of modification based 

on an hourly emissions test, which 

would then be followed by the current 

major modification provisions based on 

annual emissions. Specifically, we 

request comment on whether the major 

NSR program should include a four-step 

process as follows: (1) Physical change 

or change in the method of operation; 

(2) maximum achievable hourly 

emissions increase (or another 

alternative emissions increase test such 

as discussed below); (3) significant 

emissions increase as in the current 

major NSR regulations; (4) significant 

net emissions increase as in the current 

major NSR regulations. 

2. Test for EGUs Based on Maximum 

Achieved Hourly Emissions 

We are also proposing in the 

alternative a slightly different emissions 

test from the maximum achievable 

hourly emissions test applied in the 

NSPS program. Specifically, we are 

requesting comment on whether we 

should promulgate an emissions test 

based on assessing an emissions unit’s 

historical maximum hourly emissions. 

That is, instead of calculating what a 

source could actually emit at current 

maximum capacity, actual emissions 

would be determined by a specific 

measure of historical emissions, such as 

with CEMS. This test may be preferred 

by some because the method of 

assessing the source’s actual emissions 

is similar to the current major NSR 

approach for determining baseline 

actual emissions. 

We would call this test the maximum 

achieved hourly emissions test. Under 

this approach, an EGU would determine 

whether an emissions increase will 

occur by comparing the pre-change 

maximum actual hourly emission rate to 

a projection of the post-change 

maximum actual hourly emission rate. 

The pre-change maximum actual hourly 

emission rate would be the highest rate 

at which the EGU actually emitted the 

pollutant within the 5-year period 

immediately before the physical or 

operational change. 

Like the maximum achievable hourly 

emissions test, the maximum achieved 

emissions test is a measure of a source’s 

actual emissions. The maximum 

achieved hourly emissions test is based 

on a specific measure of historical 

actual emissions during a representative 

period. Therefore, even if our petition 

for rehearing in New York v. EPA is 

denied, we believe that a test based on 

maximum achieved hourly emissions 

satisfies the requirement that major NSR 

applicability be based on ‘‘some 

measure of actual emissions.’’

We request comment on whether 

adopting this alternative approach 

would achieve all of the policy 

objectives supporting this proposal as 

effectively as the maximum achievable 

hourly emissions test would. We stated 

that two of our goals for this proposal 

are to streamline the regulatory 

requirements applying to EGUs by 

allowing EGUs to apply the same test for 

measuring emissions increases from 

modifications under both the NSPS 

program and NSR program, and to 

provide some nationwide consistency in 

the emissions calculation procedures in 

light of the Fourth Circuit’s decision in 

Duke. We believe that the maximum 

achievable hourly emissions test could 

better comport with our policy goals 

than the maximum achieved hourly 

emissions test. Therefore, given that we 

do not believe that there is substantive 

difference in the baseline emissions 

between the two tests, we prefer 

adoption of the maximum achievable 

hourly emissions test as used in the 

NSPS program. 

61092 Federal Register / Vol. 70, No. 202 / Thursday, October 20, 2005 / Proposed Rules 

34To the extent that sources prefer to avoid major 

NSR by taking enforceable limitations on their 

potential to emit, reviewing authority resources will 

also be focused on establishing synthetic minor 

limits subject to the conditions in § 51.165(a)(5)(ii), 

§ 51.166(r)(2), and § 52.21(r)(4). That is, sources 

basically have two choices—enforceable limitations 

on emissions increases or major NSR review for 

changes that result in increases in existing capacity. 

In view of our policy goal to establish 

a uniform emissions test nationally 

under the NSPS and NSR programs for 

existing EGUs, we also request comment 

on extending the maximum achieved 

hourly emissions test to emissions 

increases in the NSPS program. 

Specifically, we request comment on 

whether we should revise 40 CFR 60.14 

to include a maximum achieved hourly 

emissions test, either in lieu of the 

maximum achievable hourly emissions 

test or in addition to the maximum 

achievable hourly emissions test. We 

intend to provide more detailed 

information concerning the maximum 

achieved hourly emissions test in the 

NSPS program in our supplemental 

proposal. 

3. Emissions Test Based on Energy 

Output 

We also request comment on adopting 

an NSR emissions test based on mass of 

emissions per unit of energy output, 

such as lb/MW hour or nanograms per 

Joule. Applicability under the major 

NSR program has historically been 

based on annual limits measured in tons 

per year. As we discuss in Section V. of 

this preamble, Congress did not specify 

how to calculate ‘‘increases’’ in 

emissions and left EPA with the task of 

filling that gap. We believe establishing 

an NSR emissions increase test based on 

mass emissions per unit of energy 

output would be a reasonable use of our 

discretion. 

We also believe that incorporating an 

output-based emissions test has merit 

for several reasons. The primary benefit 

of output-based standards is that they 

recognize energy efficiency as a form of 

pollution prevention. Using more 

efficient technologies reduces fossil fuel 

use and also reduces the environmental 

impacts associated with the production 

and use of fossil fuels. Another benefit 

is that output-based standards allow 

sources to use energy efficiency as a part 

of their emissions control strategy. 

Energy efficiency as an additional 

compliance option can lead to reduced 

compliance costs, as well as lower 

emissions. We want to encourage use of 

efficient units that displace less 

efficient, more polluting units. This 

approach is especially desirable where 

EGUs are already subject to marketbased systems such as the Acid Rain 

program, NOX SIP Call, and State 

trading programs implementing the 

CAIR, as those programs increase 

incentives for using efficient units. 

Furthermore, an output-based 

emissions test would comport with 

recent State efforts. Several States have 

initiated regulations or permits-by-rule 

for distributed generation (DG) units, 

including combustion turbines. States 

that have made efforts to regulate DG 

sources include California, Texas, New 

York, New Jersey, Connecticut, 

Delaware, Maine, and Massachusetts. 

Those State rules include emission 

limits that are output-based, and many 

allow generators that use combined heat 

and power (CHP) to take credit for heat 

recovered. For example, Texas recently 

passed a DG permit-by-rule regulation 

that gives facilities 100 percent credit 

for steam generation thermal output, 

and incorporates HRSG and duct 

burners under the same limit. The 

California Air Resources Board (CARB) 

also has output-based emission limits, 

which allow DG units using CHP to take 

a credit to meet the standards, at a rate 

of 1 MW-hr for each 3.4 million British 

thermal units (MMBtu) of heat 

recovered, or essentially, 100 percent. 

The draft rules for New York and 

Delaware also allow DG sources using 

CHP to receive credit toward 

compliance with the emission 

standards. 

We request comment on the 

desirability and feasibility of using an 

output-based test for measuring 

emissions increases in the major NSR 

program. In view of our policy goal to 

establish a uniform emissions test 

nationally under the NSPS and NSR 

programs for existing EGUs, we also 

request comment on extending an 

output-based test for measuring 

emissions increases to the NSPS 

program. Specifically, we request 

comment on whether we should revise 

40 CFR 60.14 to include an outputbased emissions test, either in lieu of 

the maximum achievable and maximum 

achieved hourly emissions tests or in 

addition to these emissions tests. We 

intend to provide more detailed 

information concerning the outputbased emissions test for both the NSR 

and NSPS programs in our 

supplemental proposal. 

C. Pollutants to Which the Revised 

Applicability Test Applies 

We request comments on our proposal 

that the revised emissions test (either 

our preferred maximum achievable test, 

the alternative maximum achieved test, 

or the output-based emissions test) 

should apply to all regulated NSR 

pollutants. In light of our policy goal to 

provide a nationally consistent program 

and to streamline major NSR for EGUs, 

we believe it is desirable to provide the 

alternative test for emissions increases 

of all regulated NSR pollutants. As 

described in detail in Section III of this 

preamble, we do not believe that today’s 

revised emissions test is substantially 

different from the actual-to-projectedactual test, particularly in light of the 

substantial SO2 and NOX emissions 

reductions that other programs have 

achieved or are expected to achieve 

from EGUs. As we describe in further 

detail in Section III.C. of this preamble, 

the application of the major NSR 

program to EGU emissions increases of 

regulated NSR pollutants other than SO2

and NOX would be unlikely to result in 

the implementation of any additional 

controls. 

D. Significant Emissions Rates 

As we stated, we are not proposing to 

allow EGUs to exclude emissions 

increases that fall below a particular 

significant emissions rate. Our current 

major NSR regulations allow sources to 

avoid major NSR applicability if the 

physical or operational change results in 

an emissions increase that is below a 

significant level. 

We codified the existing significant 

rates based on a de minimis legal theory 

that balances the administrative burden 

of running the program with the 

environmental benefit of undergoing 

major NSR review. In codifying the 

significant rates, we relied on our belief 

that Congress did not intend to regulate 

every physical or operational change at 

a major source. Because a maximum 

achievable hourly emissions rate test is 

based on computing a unit’s rate of 

emissions in kg/hr, whereas the existing 

significant rates are expressed in tons 

per year (tpy), it is more 

administratively efficient to eliminate 

the need to compute significant 

emission rates from the proposed 

emissions test. 

By eliminating the use of a significant 

emission rate threshold for 

modifications, we balance the 

differences in these tests, and focus 

permitting authority resources on 

reviewing all changes that result in 

increases in existing capacity.34 We 

believe that this result is consistent with 

our interpretation of Congressional 

intent in that it assures that, at a 

minimum, increases in existing capacity 

undergo major NSR review. See a fuller 

discussion of the legislative history in 

Section V. of this preamble. 

We request comment on our 

conclusion that the maximum 

achievable hourly emissions test should 

regulate all emissions increases and not 

Federal Register / Vol. 70, No. 202 / Thursday, October 20, 2005 / Proposed Rules 61093 

just those that are above the significant 

rate. We also request comment on the 

alternative of including a significant 

emissions rate as a component of the 

maximum achievable hourly emissions 

test for major NSR. If we include use of 

the significant rate within the emissions 

increase test, sources would have to 

extrapolate their maximum hourly 

emission rate to a maximum annual 

emission rate. We request comment on 

an appropriate approach for making this 

extrapolation. 

E. Eliminating Netting 

Netting has played an important role 

over the history of the major NSR 

program by, to some extent, allowing 

sources to manage plantwide changes in 

a way that assures that the major 

stationary source’s emissions do not 

increase. Nonetheless, numerous 

stakeholders, including individuals 

among State, environmental, and 

industry groups, believe that our netting 

procedures in the existing program are 

too complicated. State and 

environmental groups also believe 

netting allows construction of brand 

new emissions units to occur without 

requiring emissions controls. These 

stakeholders suggested removing the 

netting provisions or revising the 

procedures to shorten the 

contemporaneous period to allow for 

‘‘project netting.’’ Project netting allows 

the emissions increases and decreases 

from a given project to be summed 

together without the need to review all 

changes over the previous 5 years. 

Because the maximum achievable 

hourly emissions test is based on 

increases in kg/hr, including netting 

within the emissions test would further 

complicate administration of the 

program by adding additional 

calculations to an already complicated 

process. Accordingly, eliminating the 

ability to net pollutant increases and 

decreases would simplify applicability 

determinations and assure that increases 

in existing capacity could not occur 

without preconstruction review and 

installation of appropriate controls 

(except where sources otherwise 

establish enforceable limitations to 

avoid emissions increases) . Also, one of 

the advantages of our proposal to 

eliminate netting is that there would be 

no unreviewed increases. 

Nevertheless, the Court in Alabama 

Power held that the Act requires EPA to 

allow netting within our regulations (the 

‘‘bubble’’ approach), because such an 

approach is consistent with the 

purposes of the Act. The Court reasoned 

that Congress intended to ‘‘generate 

technological improvement in pollution 

control, but this approach focused upon 

‘rapid adoption of improvements in 

technology as new sources are built,’ not 

as old ones [plants] were changed 

without pollution increases.’’

It is important to place this ruling in 

the context of the rules before the Court 

at that time. Our 1978 regulations 

required a source-wide accumulation of 

emissions increases without providing 

for an ability to offset these accumulated 

increases with any source-wide 

decreases. In finding that we must apply 

a bubble approach, the Court held that 

we could not require sources to 

accumulate increases without also 

accumulating decreases. It is unclear 

whether the Court would have reached 

the same conclusion if the emissions 

test before the Court only considered the 

increases from the project under review 

and not source-wide increases from 

multiple projects. Moreover, contrary to 

the Alabama Power Court’s analysis, 

some have argued that the netting 

approach may have impeded Congress’

objective of promoting ‘‘rapid adoption 

of improvements in technology as new 

sources are built.’’ This is because it 

allows construction of new units at 

existing facilities without emissions 

controls, while requiring major NSR for 

large greenfield sources. 

We request comment on our 

observations related to the Alabama 

Power Court’s decision related to netting 

and whether a major NSR program 

without netting can be supported under 

the Act. Specifically, we request 

comment on whether, in adding the 

maximum achievable emissions test for 

EGUs within the major NSR program, 

we should retain the requirement to 

compute a net emissions increase. 

Under this approach, a source would 

first determine whether an activity 

results in an increase in maximum 

hourly emissions, and then the source 

would determine whether this increase, 

when considered with other increases 

and decreases at the major stationary 

source over the past 5 years, would 

result in a net emissions increase at the 

major stationary source. We also request 

comment on whether we should retain 

netting, but shorten the 

contemporaneous period to the time of 

construction and allow EGUs to use 

only ‘‘project’’ netting in computing 

whether a physical or operational 

change results in an emissions increase. 

F. Benefits of Maximum Achievable 

Hourly Emissions Test 

We believe that implementing our 

proposed maximum achievable hourly 

emissions rate test for EGUs offers 

significant benefits over the current 

actual-to-projected-actual emissions 

test. The proposed regulations (and our 

alternate proposal) would provide 

nationwide consistency in how States 

implement the major NSR program for 

EGUs. They would also establish a 

uniform emissions test nationally under 

the NSPS and NSR programs for existing 

EGUs. However, we are also requesting 

comment on whether the proposed 

maximum achievable hourly emissions 

test (and our alternate proposals) should 

be limited to the geographic area 

covered by CAIR, or to the geographic 

area covered by both CAIR and BART. 

Furthermore, the proposed 

regulations allow owner/operators to 

make changes that, without increasing 

existing capacity, promote the safety, 

reliability, and efficiency of EGUs. We 

do not want to discourage plant owners 

or operators from engaging in activities 

that are important to restoring, 

maintaining, and improving plant 

safety, reliability, and efficiency. 

Uncertainties inherent in the current 

major NSR permitting approach can 

exacerbate the reluctance to engage in 

these activities. To elaborate on the 

uncertainty issues: Unless an owner or 

operator seeks an applicability 

determination from his or her reviewing 

authority, it can be difficult for the 

owner or operator to know with 

reasonable certainty whether a 

particular activity would trigger major 

NSR. This gives the owner or operator 

five choices, two of which the owner or 

operator is not likely to select, and the 

other three of which have significant 

drawbacks for the productivity of the 

plant. 

First, the owner or operator may 

simply seek an NSR permit. That 

course, however, is likely to be timeconsuming and expensive, since it will 

likely result in a requirement to retrofit 

an existing plant with state-of-the-art 

pollution controls, which often is very 

costly and can present significant 

technical challenges. Therefore, an 

owner or operator is not likely to select 

this option if it can be avoided. 

Second, the owner or operator may 

proceed at risk without a reviewing 

authority determination. That option, 

however, is also not likely to be 

attractive where a significant 

replacement activity is involved, 

because if the owner or operator 

proceeds without a reviewing authority 

determination and if we later find that 

he or she made an incorrect 

determination on their own, the owner 

or operator faces potentially serious 

enforcement consequences. Those 

consequences could well include 

substantial fines and penalties for 

violation of the CAA (along with the 

further consequences of violation of the 

CAA) and a requirement to install stateVerDate Aug<31>2005 17:49 Oct 19, 2005 Jkt 208001 PO 00000 Frm 00026 Fmt 4702 Sfmt 4702 E:\FR\FM\20OCP1.SGM 20OCP1
61094 Federal Register / Vol. 70, No. 202 / Thursday, October 20, 2005 / Proposed Rules 

35We discuss the regulatory history related to the 

CMA Exhibit B Settlement Agreement in Section V. 

of today’s preamble. See also 67 FR 80205, 

December 31, 2002—item 0030 in E-Docket OAR–

2005–0163. 

36For a complete discussion of the emissions 

reductions and air quality impacts of the BART 

rule, see Chapter 3 of the RIA for the BART final 

rule, available at http://www.epa.gov/oar/visibility/ 

actions.html and item 0004 in E-Docket OAR–2005–

0163. 

of-the-art pollution controls, even 

though those controls present technical 

issues or represent a significant enough 

expenditure that they likely would have 

deterred the owner or operator from 

seeking a permit in the first place. The 

owner or operator is not likely to take 

this risk if he or she believes there is a 

high probability of these kinds of 

consequences and if he or she has other 

options. 

Third, the owner or operator may seek 

an applicability determination. That 

process, too, is time-consuming and 

expensive, albeit typically less so than 

seeking a permit. Furthermore, there is 

a possibility that EPA could eventually 

make a different applicability 

determination than the State has made, 

which can add more time and 

uncertainty to the process. This path 

presents a potentially significant barrier 

to EGUs and other industries. This 

approach also is likely to delay 

important projects that would enhance 

the safety, reliability, and efficiency of 

the plant while the owner/operator 

waits for the applicability 

determination. 

Fourth, the owner or operator may 

forego or curtail activities that would 

enhance the safe, reliable, or efficient 

operation of its plant, instead opting to 

repair existing components, even 

though they are inferior to current-day 

components because they probably are 

less advanced and less efficient than 

current technology. Foregoing the 

activities altogether will reduce plant 

safety, reliability and efficiency; 

curtailing or postponing them does as 

well, differing only in the degree of 

these effects. 

Finally, the owner or operator may 

curtail the plant’s productive capacity 

by replacing components with less than 

the best technology to be more certain 

that the replacement is within the 

regulatory bounds. Or he or she may 

agree to limit the source’s hours of 

operation or capacity or install air 

pollution controls that are less than 

state-of-the-art. These alternative 

courses of action, however, will also 

result in loss of plant productivity. 

The current approach to major NSR is 

also problematic for State and local 

reviewing authorities. They require the 

regulatory authorities to devote scarce 

resources to make complex 

determinations, including applicability 

determinations, and consult with other 

agencies to ensure that any 

determinations are consistent with 

determinations made for similar 

circumstances in other jurisdictions 

and/or that other reviewing authorities 

would concur with the conclusion. In 

our June 2002 report to the President, 

we concluded that the current major 

NSR program has impeded or resulted 

in the cancellation of projects that 

would have maintained and improved 

the reliability, efficiency, or safety of 

existing energy capacity. 

We believe it is desirable to change 

the approach to major NSR. The current 

approach discourages sources from 

replacing components, and encourages 

them to replace components with 

inferior components or to artificially 

constrain production in other ways. 

This behavior does not advance the 

central policy goals of the major NSR 

program as applied to existing sources. 

The central policy goal is not to limit 

productive capacity of major stationary 

sources, but rather to ensure that they 

will install state-of-the-art pollution 

controls at a juncture where it otherwise 

makes sense to do so. We also do not 

believe the outcomes produced by the 

approach we have been taking have 

significant environmental benefits 

compared with the approach we are 

proposing today. 

We believe that these problems would 

be significantly reduced by the rule we 

are proposing today. Our new approach 

would provide more certainty both to 

source owners or operators who will be 

able better to plan activities at their 

facilities, and to reviewing authorities 

who will be able better to focus 

resources on other areas of their 

environmental programs rather than on 

time-consuming determinations. The 

effect should be to remove disincentives 

to undertaking activities that improve 

efficiency, safety, reliability, and 

environmental performance. 

We also note that today’s proposed 

emissions test would simplify 

applicability determinations for sources 

by using the same test for both the NSPS 

and NSR programs. Moreover, it 

eliminates the burden of projecting 

future emissions and distinguishing 

between emissions increases caused by 

the change from those due solely to 

demand growth, because any increase in 

the emissions under the maximum 

achievable emissions test would 

logically be attributed to the change. It 

reduces recordkeeping and reporting 

burdens on sources because compliance 

will no longer rely on synthesizing 

emissions data into rolling average 

emissions. It improves compliance by 

making the rules more understandable, 

which correspondingly reduces the 

reviewing authorities’ compliance and 

enforcement burden. 

Nonetheless, despite identifying many 

of these benefits in our analysis of the 

Settlement Agreement that EPA had 

entered into in Chemical Manufacturer’s 

Association v. EPA, No. 79–112, we 

rejected the use of that approach 

because we stated that such an approach 

was not acceptable for major NSR 

applicability as a general matter.35 We 

based our conclusions on concerns that 

the Settlement Agreement Approach 

would allow facilities to generate paper 

credits for netting and offsets because 

the facility may never have operated at 

its full potential emissions. Moreover, 

we raised concerns that unreviewed 

increases could lead to increment 

violations. 

Today’s proposal differs from the 

Settlement Agreement Approach in an 

important way. We retain the existing 

procedures for calculating offset credits 

to avoid any possibility of generating 

paper reductions. Moreover, we 

requested comment on eliminating or 

limiting the availability of netting. 

Either approach would alleviate the 

possibility of generating paper 

reductions. One of the advantages of our 

proposal to eliminate netting is that 

there would be no unreviewed 

increases. (That is, all emission 

increases, including those less than 40 

tpy, would be reviewed.) On the other 

hand, if we continue to include netting 

provisions in the major NSR 

applicability test, those provisions will 

continue to be based on actual 

emissions. 

Importantly, States’ implementation 

of the Acid Rain, CAIR, and BART 

programs will generate significant 

reductions in pollution and thereby 

decrease the likelihood that an 

unreviewed source could cause an 

increment violation. We conducted 

modeling to estimate the impact of the 

CAIR program on nationwide emissions 

trends and ambient concentrations. The 

modeling shows that emissions are 

predicted to decline in all parts of the 

country. With nationwide emissions 

declining, there is a decreased 

likelihood that unpermitted emissions 

increases could violate a PSD increment 

by returning a given geographical area to 

levels above that area’s historical actual 

levels. We also conducted modeling to 

estimate the impact of the BART rule on 

nationwide emissions trends and 

visibility. The BART modeling shows 

that emissions will decline beyond 

those reductions under CAIR, 

particularly in Class I areas.36

Federal Register / Vol. 70, No. 202 / Thursday, October 20, 2005 / Proposed Rules 61095 

37For our discussion of these impacts related to 

the CAIR, see the CAIR RIA at 5–1, item 0022 in 

E-Docket OAR–2005–0163. The CAIR RIA is also 

available at http://www.epa.gov/air/ 

interstateairquality/technical.html. For our 

discussion of these impacts related to the BART, see 

the BART RIA at 5–1, available at http:// 

www.epa.gov/oar/visibility/actions.html and item 

0004 in E-Docket OAR–2005–0163. 

38See House Report 91–1146 at 5365: The 

purpose of this authority is to prevent the 

occurrence of significant new air pollution 

problems arising from or associated with such new 

sources. As explained above, such new sources may 

take the form either of entirely new facilities or 

expanded or modified facilities, or of expanded or 

modified operations which result in substantially 

increased pollution. * * * The emission 

standards shall provide that sources of such 

emissions shall be designed and equipped to 

prevent and control such emissions to the fullest 

extent compatible with the available technology 

and economic feasibility as determined by the 

Secretary. 

39CAA section 111(a)(4). This section has not 

been amended since it was inserted into the statute 

in 1970. 

40H.R. Rep 91–1146, p. 5361 (1970). 

41Congressional Record—HR 17090, June 10, 

1970 at 19212. 

42This language concerning modifications was 

never included in the NSR regulations at §§ 51.165, 

51.166, 52.21, 52.24, and Appendix S to part 51. On 

January 23, 1980 (see 45 FR 5616, item 32 in EDocket OAR–2005–0163), we amended this 

language to delete the portions of § 60.14 that 

implemented the bubble concept, which the United 

States Court of Appeals for the District of Columbia 

Circuit rejected in a decision rendered January 27, 

1978. [Asarco, Inc. v. EPA, 578 F.2d 319 (D.C. Cir. 

1978)—item 0047 in E-Docket OAR–2005–0163.] 

Following the Asarco decision, § 60.14 was 

amended to include the current provisions. 

Furthermore, our analyses estimate 

improvements in air quality related 

values from both the CAIR and BART.37

The emissions reductions from the 

programs that affect electric utilities 

principally come from cap-and-trade 

programs such as the Acid Rain 

Program, the NOX SIP Call, and the 

CAIR. Concerns have been expressed at 

times about how trading programs might 

have a disparate impact on some 

populations, especially those located 

closest to some of the affected emission 

sources. EPA is developing a 

methodology to look at the local impacts 

of these types of programs and will 

attempt to quantify the impacts on local 

communities for the final rule. 

For all the reasons we articulate in 

this section, we now believe that it is 

appropriate to consider the benefits of 

implementing the maximum achievable 

hourly emissions increase test. 

G. Would States Be Required To Adopt 

the Revised Emissions Test? 

Consistent with our longstanding 

practice, we are proposing that the 

revised emissions test would be a core, 

mandatory, minimum program element 

for SIPs implementing the part C and 

part D major NSR programs. We are also 

proposing that State and local agencies 

would submit NSR SIP revisions 

incorporating the revised emissions test 

within 12 months after promulgation of 

the final rules. For the reasons we 

articulate in Section V.C. of this 

preamble, we believe the maximum 

achievable hourly emissions test 

implements Congressional intent for the 

major NSR program and in a more 

effective manner for EGUs than the 

current major NSR program. 

Consistent with our longstanding 

practice, we are also proposing that if a 

State were to decide it does not want to 

implement the revised emissions test, 

that State would need to make a 

showing that its program is not less 

stringent than our program. 

V. Statutory and Regulatory History 

and Legal Rationale 

This section provides our legal basis 

and rationale for the proposed changes. 

In support of our legal basis and 

rationale, this section provides a more 

detailed background than that in 

Section IV. on the emissions increase 

test used in the NSPS program and 

major NSR program. 

A. The NSPS Program 

In the 1970 CAA Amendments, 

Congress included, for the first time, 

emission standards for new sources of 

air pollution, termed ‘‘new source 

performance standards’’ (NSPS). [CAA 

section 111.] The purpose of the NSPS 

program was to prevent new air 

pollution problems by requiring that 

new sources of emissions, including 

those from expanded or modified 

existing facilities, be designed and 

equipped to incorporate demonstrated 

emissions controls.38

Specifically, Congress required the 

EPA to set emission limitations for 

categories of new stationary sources of 

air pollution based on the best system 

of emissions reduction, considering 

costs, that has been adequately 

demonstrated. Congress also specifically 

required that the NSPS apply to 

modifications of existing facilities, and 

defined ‘‘modification’’ in CAA section 

111(a)(4) as follows: 

‘‘The term modification means any 

physical change in, or change in the method 

of operation of, a stationary source which 

increases the amount of any air pollutant 

emitted by such source or which results in 

the emission of any air pollutant not 

previously emitted.’’ 39

The statute does not specify how 

increases in emissions are to be 

determined and the 1970 legislative 

history does not directly speak to it. 

Nonetheless, the legislative history 

shows that, at a minimum, Congress was 

concerned about regulating new sources 

of emissions caused by expanded or 

modified capacity, as the following two 

statements indicate: 

Therefore, particular attention must be 

given to new stationary sources which are 

known to be either particularly large-scale 

polluters or where the pollutants are extra 

hazardous. The legislation, therefore, grants 

authority to the Secretary of Health, 

Education, and Welfare to establish emission 

standards for any such sources which either 

in the form of entire new facilities or in the 

form of expanded or modified facilities, or 

because of expanded or modified operation 

or capacity, constitute new sources of 

substantially increased pollution.40

Therefore, it would appear to me that, for 

instance, an old steel plant which altered its 

production of a particular unit or operation, 

even though that unit was an old unit, would 

be controlled just as its competitor, a new 

steel plant, would be controlled, where new 

equipment plus new sources of emissions 

occur? That is correct.41

On December 23, 1971 (36 FR 24877), 

we promulgated the first NSPS 

regulations. Consistent with 

Congressional intent to regulate new 

sources of emissions, these regulations 

included a definition of modification 

applying to affected facilities as follows. 

Modification means any physical change 

in, or change in the method of operation of, 

an affected facility which increases the 

amount of any air pollutant (to which a 

standard applies) emitted by such facility or 

which results in the emission of any air 

pollutant (to which a standard applies) not 

previously emitted, * * * 

Id. 

On December 16, 1975, we revised the 

definition of modification in the NSPS 

program. 40 FR 58416. Our revisions 

clarified how to measure emissions 

increases when there is a physical 

change or change in the method of 

operation at an existing facility. 

Specifically, we added the phrase 

‘‘emitted into the atmosphere’’ to the 

definition of modification at 40 CFR 

60.2 and added new provisions to 

define how to measure emissions 

increases for purposes of determining 

whether a modification occurs, at 40 

CFR 60.14.42

Our focus in adding the regulatory 

phrase ‘‘emission rate to the 

atmosphere’’ was to regulate facilities 

only when they constitute a new source 

of emissions. We do not believe that 

Congress intended to draw existing 

facilities into NSPS applicability when 

there was no increase in the amount of 

pollution that a facility could actually 

emit to the environment, either because 

the new equipment did not emit 

61096 Federal Register / Vol. 70, No. 202 / Thursday, October 20, 2005 / Proposed Rules 

43By comparison, we added, ‘‘NSR regulations 

examine total emissions to the atmosphere,’’ that is, 

‘‘emissions increases under NSR are determined by 

changes in annual emissions as expressed in tons 

per year (tpy).’’ Id. We explained how to determine 

the annual emissions as follows: 

Annual emissions may be calculated as the 

product of the hourly emissions rate times the 

utilization rate, expressed as hours of operation per 

year, or as the product of an emission factor * * * 

in units of mass emitted per unit of process 

throughput times the annual throughput * * * 

Thus, we said, both NSPS and NSR calculations 

include the hourly emission rate, but the difference 

between the two is that the NSR calculation then 

adds the annual utilization rate, expressed as hours 

of operation per year. 

pollutants or because the addition of 

control devices means that the total 

emissions rate to the atmosphere did not 

increase. In the proposed preamble, we 

described the addition of the regulatory 

term emitted into the atmosphere’’ by 

reference to ‘‘actual emissions,’’

measured as post-control emissions at 

capacity instead of potential emissions 

without controls. 

The proposed amended definition of 

‘‘modification’’ also includes a new phrase 

‘‘emitted into the atmosphere.’’ The new 

phrase clarifies that for an existing facility to 

undergo a modification there must be an 

increase in actual emissions. If any increase 

in emissions that would result from a 

physical or operational change to an existing 

facility can be offset by improving an existing 

control system or installing a new control 

system for that facility, such a change would 

not be considered a modification because 

there would be no increase in emissions to 

the atmosphere. The Administrator 

considered defining ‘‘modification’’ so that 

increases in pre controlled (potential) 

emissions would be considered 

modifications. However, the proposed 

definition of modification is limited to 

increases in actual emissions in keeping with 

the intent of section 111 of controlling 

facilities only when they constitute a new 

source of emissions * * * Section 60.14(b) 

provides four mechanisms which the 

Administrator may use (but to which he is 

not limited) in determining whether an 

increase in emissions has occurred * * * 

[T]hese techniques utilize parameters such as 

maximum production rate * * *’’

39 FR 36946, 36946–7. 

As we stated in the preamble for the 

proposal, we added the regulations in 

§ 60.14 to clarify the phrase ‘‘increases 

the amount of any air pollutant’’ in the 

definition of modification in § 60.2 . 

[See 39 FR 36946.] We did not create a 

new definition of modification in 

codifying § 60.14, but instead used 

§ 60.14 to define how to determine an 

actual emissions increase based on the 

facility’s maximum hourly emissions 

rate considering controls. Under 

§ 60.14(b), we calculate an emissions 

increase by comparing the hourly 

emissions rate before and after the 

physical or operational change using 

‘‘parameters such as maximum 

production rate * * *’’ 39 FR 36946, 

36947. We clarified in the proposed rule 

that maximum production rate should 

not be interpreted to mean the facility’s 

operating design capacity (sometimes 

referred to as name plate capacity) 

because this rate ‘‘bears little 

relationship to the actual operating 

capacity of the facility.’’ Id. at 36948. 

Instead, the maximum production rate 

refers to ‘‘that production rate that can 

be accomplished without making major 

capital expenditures.’’ Id. 

Thus, the final regulations calculate 

changes in what a source is actually able 

to emit at its capacity, considering 

controls. (We may refer to this test as 

the actually-able-to-emit test.) Under 

§ 60.14(b), we calculate an emissions 

increase by comparing the hourly 

emissions rate before and after the 

physical or operational change using 

‘‘parameters such as maximum 

production rate * * *’’ 39 FR 36946, 

36947. Some refer to this test as a 

‘‘maximum hourly potential-topotential’’ emissions test. However, 

since the NSPS test is based on actual 

operating capacity rather than design 

capacity, we believe that this potentialto-potential terminology can be 

misleading, and prefer the name 

‘‘maximum achievable hourly emission 

rate’’ which is similar to the provision 

we promulgated in the 1992 WEPCO 

rule, described below. As we discuss in 

detail in Section IV.A of this preamble, 

NSPS applicability based on maximum 

achievable hourly emissions before and 

after a change was reiterated in various 

policy memoranda and applicability 

determinations over the history of the 

program. 

On July 21, 1992, we further revised 

the NSPS regulations to clarify how we 

calculate emissions increases at electric 

utilities. [See 57 FR 32314 (final rule); 

56 FR 27630 (June 14, 1991) (proposed 

rule).] Among other things, this 

regulation further defined ‘‘capacity’’ for 

electric utilities subject to the NSPS 

program. Specifically, we indicated that 

utilities could use the highest hourly 

emissions rate achievable by the facility 

at any time during the 5 years before the 

change. 

In this rulemaking, prompted by 

litigation involving the Wisconsin 

Electric Power Company and commonly 

called the WEPCO rule, we noted that 

the pre-existing NSPS program 

‘‘examines maximum hourly emission 

rates, expressed in kilograms per hour,’’

that is, ‘‘[e]missions increases for NSPS 

purposes are determined by changes in 

the hourly emissions rates at maximum 

physical capacity.’’ 57 FR 32316. We 

explained how to determine an hourly 

rate, as follows. 

An hourly emissions rate may be 

determined by a stack test or calculated from 

the product of the instantaneous emissions 

rate, i.e., the amount of pollution emitted by 

a source, after control, per unit of fuel 

combusted or material processed (such as 

pounds of sulfur dioxide emitted per ton of 

coal burned) times the production rate (such 

as tons of coal burned per hour) * * * 

Id., n. 5.43

One of the purposes of the WEPCO 

rule was to address problems that 

resulted from the pre-existing method of 

calculating the maximum hourly 

emissions rate for NSPS purposes. We 

stated the following. 

Under current regulations, the emissions 

rate before and after a physical or operational 

change is evaluated at each unit by 

comparing the current hourly potential 

emissions at maximum operating capacity to 

hourly emissions at maximum capacity after 

the change. In this calculation, the reviewing 

authority disregards the unit’s maximum 

design capacity. The original design capacity 

of a unit, to the extent it differs from actual 

maximum capacity at the time that the 

baseline is established due to physical 

deterioration of the facility, is immaterial to 

this calculation. 

57 FR 32330. We stated that current 

regulations presented the problem of 

‘‘undue emphasis on the physical 

condition of the affected facility 

immediately prior to the change * * * 

For instance, if a unit has broken down 

and is in need of repairs, the utility’s 

baseline will be artificially low.’’ Id. 

Accordingly, we revised the baseline 

requirement for electric utilities to 

include the following constraint. 

No physical change, or change in the 

method of operation, at an existing electric 

utility steam generating unit shall be treated 

as a modification for the purposes of this 

section provided that such change does not 

increase the maximum hourly emissions of 

any pollutant regulated under this section 

above the maximum hourly emissions 

achievable at that unit during the 5 years 

prior to the change. 

40 CFR 60.14(h). In characterizing this 

requirement as a ‘‘modest’’ change from 

the pre-existing regulation, we 

described this requirement as a 

More flexible provision [that] enables units 

to establish a baseline that is representative 

of its physical and operational capacity in 

recent years, while still precluding the use of 

a baseline tied to original design capacity, 

which * * * may bear no relationship to the 

facility’s capacity in recent years. 

57 FR 32330. Therefore, the WEPCO 

rule makes clear that the NSPS 

applicability test for EGUs is the same 

test (that is, the actually-able-to-emit 

Federal Register / Vol. 70, No. 202 / Thursday, October 20, 2005 / Proposed Rules 61097 

44Before 1990, Congress provided States with two 

options for managing the impact of economic 

growth on emissions. A State could either provide 

a case-by-case review of each new or modified 

major source and require such source to obtain 

offsetting emissions, or the State could implement 

a waiver provision which allowed the State to 

develop an alternative to the case-by-case emissions 

offset requirement. This alternative program became 

known as the ‘‘growth allowance’’ approach. In 

1990, Congress invalidated some of the existing 

growth allowances and shifted the emphasis for 

managing growth from using growth allowances to 

using the case-by-case offset approach. 

45See the first nonattainment area regulations at 

Appendix S to part 51, December 21, 1976, at 41 

FR 55528/1—see item 0034 in E-Docket OAR–2005–

0163. Similarly, a ‘‘major modification’’ shall 

include a modification to any structure, building, 

facility, installation or operation (or combination 

thereof) which increases the allowable emission 

rate by the amounts set forth above. See also our 

1978 regulations at 43 FR 26380 item 0035 in EDocket OAR–2005–0163. 

test) that is generally applicable. Thus, 

the only difference in the NSPS 

applicability test for EGUs and nonEGUs is the method for determining the 

actual operating capacity; for EGUs it is 

the actual operating capacity at any time 

in the previous 5 years and for nonEGUs it is actual operating capacity that 

is achievable without a capital 

expenditure. 

B. The Major NSR Program 

EPA promulgated the first set of PSD 

regulations in 1974 (39 FR 42510), and 

the first nonattainment major NSR 

programs in 1976 (41 FR 55524). At that 

time, the Act did not contain specific 

provisions for these programs. Instead, 

the PSD program evolved from a lawsuit 

claiming that the Act required EPA to 

ensure that air quality did not 

deteriorate in areas where air quality 

met the NAAQS. Sierra Club v. 

Ruckelshaus, 344 F.Supp. 253 (D.D.C 

1972). We issued the first nonattainment 

NSR regulations (known as the Emission 

Offset Interpretative ruling) because 

attainment dates had passed and we 

received questions as to whether, and to 

what extent, new stationary sources 

could locate in areas that failed to meet 

the attainment date. 

Our preamble to the 1974 PSD rules 

explained that we intended the PSD 

definition of ‘‘modified source’’ to be 

consistent with the definition of that 

term under the NSPS regulations. 39 FR 

42510, 42513. Accordingly, the 1974 

PSD regulations defined ‘‘modification’’

in essentially the same way for both 

programs. [See 40 CFR 52.01(d); 39 FR 

42514; 1975.] Similar to the NSPS 

provisions, EPA also included an 

exclusion for increases in production 

rate and hours of operation within the 

regulatory definition of physical change 

in or change in the method of operation. 

Congress expressly added an 

expanded preconstruction permitting 

program for new and modified major 

stationary sources to the CAA in 1977. 

The 1977 Amendments contained 

different preconstruction permitting 

requirements for major stationary 

sources in attainment and 

nonattainment areas. In areas meeting 

the NAAQS (‘‘attainment’’ areas) or for 

which there is insufficient information 

to determine whether they meet the 

NAAQS (‘‘unclassifiable’’ areas), 

Congress added requirements for the 

PSD program in part C of title I of the 

Act. Congress required States to amend 

their implementation plans to include 

requirements to prevent the significant 

deterioration of air quality where such 

air quality is presently cleaner than 

existing ambient air quality standards. 

The main focus of the PSD program was 

a ceiling on incremental pollution 

growth. The statute at sections 163(b) 

and 165(d) included specific 

‘‘increments,’’ or maximum allowable 

increases in particulates and sulfur 

dioxide. In section 166, the 1977 

Amendments also required EPA to 

propose regulations for increments or 

other means for preventing significant 

deterioration that would result from the 

other criteria pollutants. To ensure 

protection of increments and other 

means of preventing significant 

deterioration, Congress established a 

preconstruction permitting program for 

major sources that required installation 

of BACT for major sources. Thus 

Congress established the PSD program 

to allow for economic growth in 

attainment areas, to be accomplished 

primarily through preservation of 

increment. The PSD program is 

implemented primarily through SIPapproved State preconstruction 

permitting programs meeting the 

requirements of our regulations at 40 

CFR 51.166. Where we have not 

approved a SIP for an attainment or 

unclassifiable area, the program is 

implemented by us or by the States 

according to the requirements in 40 CFR 

52.21. 

Congress in 1977 was likewise 

concerned with permitting new or 

modified facilities in nonattainment 

areas. The House proposed a new CAA 

section 117 for nonattainment areas ‘‘as 

a means of assuring realization of the 

dual goals of attainment air quality 

standards and providing for new 

economic growth.’’ [H.R. Report 95–294, 

p. 19 (1977), U.S. Code Cong. & Admin. 

News 1977, p. 1091.] Thus, Congress 

added the preconstruction permitting 

program for major stationary sources in 

nonattainment areas in part D of title I 

of the 1977 CAA at section 173. The 

basic requirements of the program as 

Congress established them in CAA 

section 173 are still in place: (1) Each 

major stationary source must go through 

preconstruction review; (2) the total 

allowable emissions from new and 

modified sources must be offset; 44 (3) 

the source must comply with the lowest 

achievable emission rate (LAER); (4) 

there must be a demonstration that all 

major stationary sources in the State 

that have the same owner or operator 

are in compliance; and (5) an alternative 

sites analysis must be conducted. The 

preconstruction permitting program for 

major stationary sources in 

nonattainment areas, commonly known 

as the nonattainment major NSR 

program, is generally implemented 

through the SIP according to our 

regulations at 40 CFR 51.165. In 

transition periods before SIP approval, 

permits must be issued meeting the 

conditions of 40 CFR Appendix S, 

which reflects substantially the same 

requirements as those in § 51.165. 

Following the enactment of the major 

NSR program in the 1977 CAA, in 1978 

we promulgated comprehensive changes 

to the PSD and nonattainment major 

NSR regulations to carry out the 

statutory changes. 43 FR 26380. In the 

absence of statutory language on how to 

determine an emissions increase, we 

initially defined emissions increases in 

terms of allowable or potential 

emissions.45 As with the NSPS 

regulations, we defined potential 

emissions as uncontrolled emissions. 

Nonetheless, when we interpreted 

111(a)(4) for the major NSR program, we 

concluded that the NSPS and NSR 

program have different purposes. We 

believed that the NSPS-based 

definitions and interpretations should 

not be controlling for NSR purposes. 

Accordingly, in our 1978 final rules, we 

defined ‘‘modification’’ for NSR 

differently than we defined it in the 

NSPS program by including a plantwide 

approach for reviewing emissions 

increases (netting), even though the 

Court held this approach unlawful as 

applied in the NSPS program. [Asarco, 

Inc. v. EPA, 578 F.2d 319 (D.C. Cir. 

1978).] 

Numerous aspects of our 1978 final 

rules were challenged by industry, State 

and environmental petitioners. In June 

1979, the D.C. Circuit Court issued a per 

curiam (preliminary) opinion. [Alabama 

Power Co. v. Costle, 606 F.2d 1068 (D.C. 

Cir. 1979).] In response to that opinion, 

we immediately undertook to revise our 

regulations consistent with that opinion 

and proposed significant changes to the 

method for determining whether a 

change constitutes a major modification. 

Under the proposal, a major 

61098 Federal Register / Vol. 70, No. 202 / Thursday, October 20, 2005 / Proposed Rules 

46The Court amended the December 14th opinion 

on April 21, 1980. See item 0024 in E-Docket OAR–

2005–0163. 

47The regulations define ‘‘electric utility steam 

generating units’’ as any steam electric generating 

unit that is constructed for the purpose of supplying 

more than one-third of its potential electric output 

capacity and more than 25 megawatts (MW) of 

electrical output to any utility power distribution 

system for sale. See, for example, § 51.166(b)(30). 

48The Court expressed a view that Congress’

failure to expressly incorporate the NSPS regulatory 

definition of NSPS argues against a finding that 

Congress intended the NSPS definition to apply in 

implementing the NSR program. Id. at 25. 

modification would occur if a source 

increased its potential to emit a 

pollutant. 

On December 14, 1979, the Court in 

Alabama Power issued an opinion that 

superseded its per curiam decision. 

[Alabama Power v. Costle, 636 F.2d 323 

(D.C. Cir. 1979).] 46 EPA interpreted the 

Court’s opinion as focusing on ‘‘actual 

emissions’’ rather than ‘‘potential to 

emit.’’ [45 FR 52676, 52700.] This led 

EPA to amend its NSR regulations and 

to change the baseline for measuring 

emissions increases from using a 

source’s potential to emit to using the 

source’s ‘‘actual emissions.’’ The final 

rules generally defined pre-change 

actual emissions based on historical 

emissions (the average of annual 

emissions for the 2 years preceding the 

change), but also included provisions to 

allow source-specific allowables or 

potential to emit to be a measure of prechange actual emissions in certain 

circumstances. [See 40 CFR 

52.21(b)(21).] 

Our 1980 regulations resulted in 

numerous challenges, including 

challenges to our methodology for 

calculating emissions increases. These 

challenges were consolidated in 

Chemical Manufacturer’s Association v. 

EPA, No. 79–112. EPA entered into a 

Settlement Agreement which required 

us to propose an NSPS-like, hourlypotential-to-hourly-potential emissions 

increase test for modifications (‘‘CMA 

Exhibit B’’). 

In 1992, before implementing the 

Settlement Agreement, we promulgated 

revisions to our applicability regulations 

creating special rules for physical and 

operational changes at EUSGUs. [See 57 

FR 32314 (July 21, 1992).] 47 In this rule, 

as noted above, commonly referred to as 

the ‘‘WEPCO rule,’’ we adopted an 

actual-to-future-actual methodology for 

all changes at EUSGUs except the 

construction of a new electric generating 

unit or the replacement of an existing 

emissions unit. Under this 

methodology, the actual annual 

emissions before the change are 

compared with the projected actual 

emissions after the change to determine 

if a physical or operational change 

would result in a significant increase in 

emissions. To ensure that the projection 

is valid, the rule requires the utility to 

track its emissions for the next 5 years 

and provide to the reviewing authority 

information demonstrating that the 

physical or operational change did not 

result in an emissions increase. 

In promulgating the WEPCO rule, we 

also adopted a presumption that utilities 

may use as baseline emissions the actual 

annual emissions from any 2 

consecutive years within the 5 years 

immediately preceding the change. 

On July 23, 1996, we proposed CMA 

Exhibit B as one alternative as part of a 

comprehensive proposal to reform the 

NSR regulations. [61 FR 38250.] Finally, 

on December 21, 2002, we took final 

action on certain elements of our 1996 

proposal and declined to promulgate the 

CMA Exhibit B approach. Instead, we 

revised the emissions calculation 

procedures to include an actual-toprojected-actual emissions test for all 

sources. [67 FR 80290.] 

While industry, environmental groups 

and States filed petitions for review 

with the United States Court of Appeals 

for the District of Columbia Circuit 

regarding both our 1980 and 1992 rules, 

those challenges were not heard and 

decided until earlier this year when 

those challenges were consolidated with 

challenges to our 2002 revisions to the 

major source NSR program. [See New 

York v. EPA, No. 02–1387 (D.C. Cir. 

June 24, 2005).] The Court upheld EPA’s 

regulations concerning the actual-toprojected-actual test. Id., slip op. at 26. 

While industry argued that the statute 

requires EPA to use the same definition 

of ‘‘modification’’ for the NSPS program 

and NSR programs, the Court concluded 

that industry had waived the argument 

and thus declined to address this issue 

in its ruling.48

In a separate part of its opinion, the 

Court held that EPA had discretion in 

defining the period of time over which 

to calculate emissions, for purposes of 

ascertaining whether a physical or 

operational change increases those 

emissions. Id. at 39–40. The Court 

upheld EPA regulations that revised that 

period as a 2-year period within the 10 

years prior the change. The Court stated: 

In enacting the NSR program, Congress did 

not specify how to calculate ‘‘increases’’ in 

emissions, leaving EPA to fill in that gap 

while balancing the economic and 

environmental goals of the statute [citation 

omitted]. Based on its experience with the 

NSR program and its examination of the 

relevant data, EPA determined that a ten-year 

lookback period would alleviate the 

problems experienced under the 1980 rule 

and advance the economic and 

environmental goals of the CAA * * * [W]e 

defer to EPA’s statutory interpretation under 

Chevron step 2 * * *. 

Id. at 39–40. 

In another part of the Court’s opinion, 

the Court held that the NSR 

modification requirement, which 

incorporates by reference CAA section 

111(a)(4), ‘‘unambiguously defines 

‘increases’ in terms of actual 

emissions.’’ Id. at 62. EPA has filed a 

petition for rehearing in which we argue 

that this holding was in error, and that 

the term ‘‘increases’’ is ambiguous for 

NSR purposes and therefore EPA has 

discretion to promulgate an actuals, 

allowables, or potentials interpretation. 

On June 15, 2005, the United States 

Court of Appeals for the Fourth Circuit 

handed down a decision concerning an 

enforcement action against Duke Energy 

Corporation concerning major NSR 

applicability at eight electric utilities. 

[United States v. Duke Energy Corp., No. 

04–1763.] The Court ruled that ‘‘because 

Congress mandated that the PSD 

definition of ‘modification’ be identical 

to the NSPS definition of ‘modification,’

the EPA cannot interpret ‘‘modification’’

under the PSD inconsistently with the 

way it interprets that term under the 

NSPS.’’ Id., slip op. at 12–14). The Court 

also stated that ‘‘No one disputes that 

prior to enactment of the PSD statute, 

the EPA promulgated NSPS regulations 

that define the term ‘‘modification’’ so 

that only a project that increases a 

plant’s hourly rate of emissions 

constitutes a ‘modification’ ’’ Id., slip 

op. at 18. The Court thus held that for 

purposes of the PSD program, emissions 

increases must be determined by 

comparing the pre- and post-change 

maximum hourly emissions. 

C. Legal Rationale 

1. Maximum Achievable Hourly 

Emissions Test 

Sections 169(2)(C) and 171(4) of the 

Act specify that the definition of 

‘‘modification’’ set forth in CAA section 

111(a)(4) applies in the PSD and 

nonattainment major NSR programs. 

Pursuant to CAA section 111(a)(4), the 

term modification means ‘‘any physical 

change or change in the method of 

operation of a stationary source which 

increases the amount of any air 

pollutant emitted by such source or 

which results in the emission of any air 

pollutant not previously emitted.’’ The 

statute, however, does not prescribe the 

methodology for determining when an 

emissions increase has occurred 

following a physical change or change 

in the method of operation. New York v. 

EPA, slip op. at 31, 39–40, No. 02–1387 

Federal Register / Vol. 70, No. 202 / Thursday, October 20, 2005 / Proposed Rules 61099 

49The 1980 rules revised the pre-change 

(baseline) emissions calculation to one based on 

actual emissions, but retained potential-to-emit for 

measuring post-change emissions. 

(D.C. Cir. June 24, 2005). Since Congress 

did not specify how to calculate 

‘‘increases’’ in emissions, it left EPA 

with the task of filling that gap while 

balancing the economic and 

environmental goals of the CAA. Id. at 

39–40. 

When a statute is silent or ambiguous 

with respect to specific issues, the 

relevant inquiry for a reviewing court is 

whether the Agency’s interpretation of 

the statutory provision is permissible. 

Chevron U.S.A., Inc. v. NRDC, Inc., 467 

U.S. 837, 865 (1984). Accordingly, EPA 

has the discretion to propose a 

reasonable method by which to 

calculate emissions increases for 

purposes of NSR applicability. Although 

we do not assert that the NSPS 

interpretation is the only one we can 

adopt for NSR purposes (we followed 

quite a different interpretation from 

1980 until today), at the very least we 

believe that the statutory silence on this 

issue delineates a zone of discretion 

within which EPA may operate. 

As we discuss in the previous section 

of this preamble, we modeled our early 

major NSR method for calculating any 

emissions increases after the existing 

NSPS program. In the NSPS program, 

we define major modification as the 

maximum achievable hourly increase in 

emissions at actual operating capacity, 

considering controls. That is, we 

defined actual emissions as postcontrolled emissions at current capacity. 

Our early NSR regulations defined 

emissions increases in terms of 

allowable or potential emissions, 

consistent with our interpretation that 

Congress intended the modification 

definition to apply to expansions in 

capacity, but not to apply to the use of 

existing capacity. 

As we previously explained, we 

promulgated the actual-to-potential 

emissions test 49 in 1980, after 

interpreting the Alabama Power final 

decision as shifting the focus from 

regulating increases in existing capacity 

to regulating possible changes in actual 

emissions. Our decision to change to a 

historical actual emissions baseline 

must be viewed in light of the progress 

of air quality programs at that time. The 

air quality was significantly degraded in 

a number of areas and air emission 

trends showed a steady decline in the 

quality of our nation’s air in some 

jurisdictions. State and local air 

pollution control programs were just 

developing, and the programs mandated 

in 1990 by parts 2, 3, and 4 of title I of 

the Act and programs such as the Acid 

Rain program, the NOX SIP Call, CAIR, 

and BART did not exist. Accordingly, 

the major NSR program provided States 

one of the few opportunities under the 

Clean Air Act to mitigate rising levels of 

air pollution through regulation of 

potential emissions increases from 

existing sources. Moving to an actual-topotential applicability test was a 

sensible approach for managing air 

quality at that time, and interpreting the 

Alabama Power final decision to 

support this goal was appropriate. 

The Alabama Power Court recognized 

EPA’s discretion to define the same 

statutory terms differently in the NSR 

and NSPS regulations. [Alabama Power 

Co. v. Costle, 636 F.2d at 397–98 (EPA 

has latitude to adopt definitions of the 

component terms of ‘‘source’’ that are 

different in scope from those that may 

be employed for NSPS and PSD, due to 

differences in the purpose and structure 

of the two programs).] Moreover, while 

the Court held that potential to emit 

must be determined considering 

controls, and that NSR major 

modifications must be determined 

considering total or net emissions from 

the source over a contemporaneous 

period, the Court otherwise left it to 

EPA’s discretion to determine how 

emissions increases following a physical 

change or change in the method of 

operation were to be determined, 

including the currency for measuring 

the emissions increases. Id. at 353–54, 

401–03. 

In using our discretion for defining 

the component term ‘‘increases in any 

pollutant emitted’’ within the definition 

of ‘‘modification,’’ we are mindful of 

Congress’ directive that the major NSR 

program be tailored in such a way as to 

balance the need for environmental 

protection against the desires to 

encourage economic growth. In this 

context, the appropriate methodologies 

for measuring emissions increases is 

inherently linked to our responsibility 

to guide the States in their efforts to 

achieve and maintain an effective, 

comprehensive air quality program, of 

which the major NSR program is only 

one component. See section 101(a) of 

the Act. Accordingly, as both we and 

the States have gained experience in 

managing air quality, we have amended 

the applicability provisions of the NSR 

regulations to better balance the need 

for environmental protection and 

economic growth, and the 

administrative burden of running the 

program. (See for example 57 FR 32314, 

July 21, 1992; 67 FR 80186, December 

31, 2002; 68 FR 61248, October 27, 

2003.) 

In light of the progress of air quality 

programs under the 1990 CAA to reduce 

EGU emissions and the policy goals of 

the major NSR program, we considered 

the appropriate scope of the major NSR 

program as it applies to existing sources. 

The NSR program’s scope is closely 

related to the scope of the NSPS 

program, created 7 years earlier in the 

CAA Amendments of 1970. In section 

111 of the CAA, which sets forth the 

NSPS provisions, Congress applied the 

NSPS to ‘‘new sources.’’ [CAA sections 

111(b)(1)(B), 111(b)(4).] Congress 

determined that as a general matter it 

would not impose the NSPS standards 

on existing sources, instead leaving to 

the State and local permitting 

authorities the decision of the extent to 

which to regulate those sources through 

‘‘State Implementation Plans’’ designed 

to implement National Ambient Air 

Quality Standards (NAAQS). [See CAA 

section 110.] Congress followed a 

similar approach in determining the 

scope of the major NSR program 

established by the 1977 Amendments to 

the CAA. As amended, the CAA 

specifies that State Implementation 

Plans must contain provisions that 

require sources to obtain major NSR 

permits prior to the point of 

‘‘construction’’ of a source. [CAA 

sections 172(c)(5); 165(a).] By contrast, 

the CAA generally leaves to State and 

local permitting authorities in the first 

instance the question of the extent, 

means, and timetable for obtaining 

reductions from existing sources that are 

needed to comply with NAAQS. [See 

CAA sections 172(c)(1), 161.] NSR’s 

applicability to existing sources that 

undergo a ‘‘modification’’ is an 

exception to this basic concept. This 

exception likewise finds its roots in the 

NSPS program’s applicability to 

‘‘modifications’’ of existing sources. The 

1970 CAA made the NSPS program 

applicable to modifications through its 

definition of a ‘‘new source,’’ which it 

defined as ‘‘any stationary source, the 

construction or modification of which is 

commenced after the publication of 

regulations * * * prescribing a[n 

applicable] standard of performance 

* * *.’’ [CAA section 111(a)(2).] CAA 

section 111(a)(4), in turn, defined a 

‘‘modification’’ as ‘‘any physical change 

in, or change in the method of operation 

of, a stationary source which increases 

the amount of any air pollutant emitted 

from such source or which results in the 

emission of any air pollutant not 

previously emitted.’’

61100 Federal Register / Vol. 70, No. 202 / Thursday, October 20, 2005 / Proposed Rules 

50 45 FR 52676, August, 7, 1980; 57 FR 32314, 

July 21, 1992; 67 FR 80186, December 31, 2002. See 

items 0036, 0027, and 0030 in E-Docket OAR–2005–

0163. 

51As previously stated, the United States has 

filed a petition for rehearing on this aspect of the 

Court’s decision in New York v. EPA. See item 0050 

in E-Docket OAR–2005–0163. 

52See also 36 FR 24876, December 23, 1971. 

Referring to performance tests, we stated that 

‘‘Procedures have been modified so that the 

equipment will have to be operated at maximum 

expected production rate, rather than rated 

capacity, during compliance tests.’’

The 1980, 1992 and 2002 rules 50 were 

reasonable interpretations of the 

statutory language in CAA section 

111(a)(4) for purposes of the major NSR 

program and the air quality needs of the 

country at those times, and continue to 

be reasonable in many respects. 

Nonetheless, we retain discretion to 

adopt other constructs for determining 

emissions increases following a physical 

change or change in the method of 

operation when they make sense in 

particular circumstances. The proposed 

regulations would establish a uniform 

emissions test nationally under the 

NSPS and NSR programs for existing 

EGUs. They would also streamline 

requirements for EGUs. Accordingly, we 

believe that it is appropriate to tailor the 

major NSR program for EGUs to regulate 

modifications that result in increases to 

an EGU’s existing capacity. The 

maximum achievable hourly emissions 

test is an appropriate tool for this 

purpose. 

The Court in New York v. EPA held 

that the language of the CAA indicates 

that Congress intended to apply NSR to 

changes that increase actual emissions, 

instead of potential or allowable 

emissions. Slip op. at 64. The Court 

based its opinion, in part, on the 

Alabama Power Court’s finding that the 

term ‘‘emit’’ in the phrase ‘‘emit, or have 

the potential to emit’’ within the 

definition of major emitting facility, is 

‘‘some measure of actual emissions.’’

New York v. EPA, slip op. at 63, citing 

Alabama Power, 636 F.2d at 353 

(emphasis added).51

To the extent that the Alabama Power 

Court’s holding relating to the definition 

of major emitting facility in CAA section 

169(1) should have any persuasive value 

in interpreting a different component 

term (increases the amount of any air 

pollutant) in a different definition 

[definition of modification in CAA 

111(a)(4)] in the Act, the Court’s 

reference to ‘‘some measure of actual 

emissions’’ indicates that the statute 

allows for different ways of measuring 

actual emissions. 

We believe that the maximum 

achievable hourly emissions test 

provides ‘‘some measure of actual 

emissions.’’ For most, if not all EGUs, 

the amount at which the unit is actually 

able to emit—its maximum achievable 

hourly rate—is equivalent to that unit’s 

maximum actual hourly rate during the 

relevant period. States require most, if 

not all EGUs, to perform periodic 

performance tests under applicable 

State Implementation Plans and 

enhanced monitoring requirements. The 

NSPS regulations require a source to 

conduct testing based on representative 

performance of the affected facility, 

generally interpreted as performance at 

current maximum physical and 

operational capacity. [40 CFR 60.8(c).] 52

Also, in the National Stack Test 

Guidance that we issued on September 

30, 2005, we recommended that 

facilities conduct performance tests 

under conditions that are ‘‘most likely 

to challenge the emissions control 

measures of the facility with regard to 

meeting the applicable emission 

standards, but without creating an 

unsafe condition.’’ Most EGUs actually 

emit at the highest level at which they 

are capable of emitting at some time 

within a 5-year baseline period. 

One way in which the maximum 

achievable hourly emissions test differs 

from the way actual emissions are 

measured under the current actual-toprojected-actual test is that the former 

measures actual emissions over an 

hourly period rather than over an 

annual period. When Congress enacted 

the 1977 amendments to the CAA 

creating the NSR program, it did not 

specify how increases in emissions were 

to be calculated, or over what increment 

of time emissions should be measured. 

Nonetheless, Congress was likely aware, 

before it enacted the 1977 Amendments, 

that we calculated emissions increases 

in terms of kg/hr to determine whether 

a project resulted in a ‘‘modification.’’

Congress did not indicate anywhere in 

the 1977 Amendments or the legislative 

history that our use of a kg/hr measure 

of emissions would be contrary to the 

purposes of the NSR program. 

Accordingly, we believe that we have 

discretion to determine the appropriate 

increment of time over which to 

measure actual emissions for purposes 

of determining whether emissions 

increases have occurred in the major 

NSR program. 

We believe that it is reasonable to use 

an hourly period to calculate actual 

emissions for purposes of measuring 

emissions increases in the major NSR 

program. Prior to Congress’ enactment 

of the major NSR provisions in the CAA 

Amendments of 1977, the NSPS 

regulations calculated emissions 

increases from physical and operational 

changes in terms of hourly emissions. 

Our 1975 NSPS regulations provided 

that ‘‘any physical or operational change 

to an existing facility which results in 

an increase in the emission rate to the 

atmosphere of any pollutant to which a 

standard applies shall be considered a 

modification within the meaning * * * 

of the Act,’’ with ‘‘emission rate * * * 

expressed as kg/hr of any pollutant 

discharged to the atmosphere.’’ [40 FR 

58416, 58419 (December 16, 1975)] Even 

before the 1975 NSPS rule, we put forth 

a definition of ‘‘modification’’ in a 1974 

regulation implementing what became 

known as the ‘‘Prevention of Significant 

Deterioration’’ program. [39 FR 42510 

(December 5, 1974).] The regulation’s 

preamble further provided that we 

intended the term ‘‘modified source’’ to 

be ‘‘consistent with the definition used 

in the [NSPS].’’ Id. at 42513. 

We further believe that today’s 

revised emissions test does not result in 

a substantially different outcome from 

the actual-to-projected-actual test. The 

current major NSR regulations measure 

actual emissions differently from the 

emissions test we are proposing by 

assessing changes in emissions relative 

to historical emissions over a baseline 

period defined in terms of annual 

emissions. Nonetheless, like the NSPS 

test, the major NSR regulations allow for 

consideration of an emissions unit’s 

operating capacity in determining 

whether a change results in an 

emissions increase. Under the actual-toprojected-actual test, a source can 

subtract from its post-project emissions 

those emissions that the unit could have 

accommodated during the baseline 

period and that are unrelated to the 

change (sometimes referred to as the 

‘‘demand growth exclusion’’). That is, 

the source can emit up to its current 

maximum capacity without triggering 

major NSR under the actual-toprojected-actual test, as long as the 

increase is unrelated to the physical or 

operational change. The NSPS approach 

thus differs from the major NSR test 

only by when a source considers 

operating capacity in the methodology, 

and by assuming that a source’s use of 

existing operating capacity is unrelated 

to the change. 

Although the approaches differ, 

applying the maximum achievable 

hourly emissions test for EGUs in the 

major NSR program has merit because it 

reduces the administrative burden of the 

NSR program. It eliminates the burden 

of projecting future emissions and 

distinguishing between emissions 

increases caused by the change from 

those due solely to demand growth, 

because any increase in the emissions 

under the maximum achievable 

Federal Register / Vol. 70, No. 202 / Thursday, October 20, 2005 / Proposed Rules 61101 

emissions test would logically be 

attributed to the change. It reduces 

recordkeeping and reporting burdens on 

sources because compliance will no 

longer rely on synthesizing emissions 

data into rolling average emissions. In 

view of this, allowing use of the 

maximum achievable hourly rate test 

reasonably balances the economic need 

of sources to use existing operating 

capacity with the environmental benefit 

of regulating those emissions increases 

related to a change. Moreover, allowing 

use of this approach for EGUs is a 

reasonable use of our discretion to 

define how we measure emissions 

increases for purposes of the major NSR 

program, because it reduces 

administrative burden associated with 

the emissions calculation procedure, 

and considers the effectiveness of other 

regulatory programs in regulating use of 

existing EGU capacity. 

Finally, the test allows sources to 

undertake projects designed to improve 

the efficiency, reliability, and safety of 

the EGU without necessitating a finding 

that post-change emissions at such a 

unit are unrelated to regulated physical 

or operational changes. In our 2003 final 

rule on the Equipment Replacement 

Provision of the Routine Maintenance, 

Repair and Replacement Exclusion for 

NSR (68 FR 61248, October 27, 2003), 

we articulated our position that 

activities designed to promote safety, 

reliability, and efficiency of emissions 

units should not be subject to major 

NSR, yet it is often these types of 

projects that raise questions as to 

whether post-change emissions are 

related to a change. The maximum 

achievable hourly emissions test 

encourages sources to undertake such 

projects by focusing reviewing authority 

resources on changes that add new 

operating capacity rather than on 

projects that restore a source to normal 

operations. Importantly, short-term 

emissions are a good indicator for 

operating capacity. That is, longer 

averaging periods, such as an annual 

basis, can mask spikes in production. 

2. Maximum Achieved Hourly 

Emissions Test 

As we stated in Section IV.B. of this 

preamble, we also believe that, like the 

maximum achievable hourly emissions 

test, the maximum achieved emissions 

test is a measure of a source’s actual 

emissions. The maximum achieved 

hourly emissions test is based on a 

specific measure of historical actual 

emissions during a representative 

period. Therefore, even though it is not 

our preferred option, we believe that a 

test based on maximum achieved hourly 

emissions satisfies the requirement that 

major NSR applicability be based on 

‘‘some measure of actual emissions.’’

For the reasons that we state in Section 

V.C.1 of this preamble, we believe we 

have discretion to adopt a maximum 

hourly achieved emissions test for 

determining whether there is an 

increase in emissions following a 

physical change or change in the 

method of operation. We request 

comment on this option and on whether 

it satisfies the requirement that major 

NSR applicability be based on a 

measure of actual emissions. 

We request public comment on all 

aspects of the legal basis in today’s 

proposed action. 

VI. Statutory and Executive Order 

Reviews 

A. Executive Order 12866—Regulatory 

Planning and Review 

Under Executive Order 12866 (58 FR 

51735, October 4, 1993), the Agency 

must determine whether the regulatory 

action is ‘‘significant’’ and therefore 

subject to Office of Management and 

Budget (OMB) review and the 

requirements of the Executive Order. 

The Order defines ‘‘significant 

regulatory action’’ as one that is likely 

to result in a rule that may: 

(1) Have an annual effect on the 

economy of $100 million or more or 

adversely affect in a material way the 

economy, a sector of the economy, 

productivity, competition, jobs, the 

environment, public health or safety, or 

State, local, or tribal governments or 

communities; 

(2) Create a serious inconsistency or 

otherwise interfere with an action taken 

or planned by another agency; 

(3) Materially alter the budgetary 

impact of entitlements, grants, user fees, 

or loan programs, or the rights and 

obligations of recipients thereof; or 

(4) Raise novel legal or policy issues 

arising out of legal mandates, the 

President’s priorities, or the principles 

set forth in the Executive Order. 

Pursuant to the terms of Executive 

Order 12866, OMB has notified EPA 

that it considers this a ‘‘significant 

regulatory action’’ within the meaning 

of the Executive Order. EPA has 

submitted this action to OMB for 

review. Changes made in response to 

OMB suggestions or recommendations 

will be documented in the public 

record. 

B. Paperwork Reduction Act 

The information collection 

requirements in this proposed rule have 

been submitted for approval to the 

Office of Management and Budget 

(OMB) under the Paperwork Reduction 

Act, 44 U.S.C. 3501 et seq. The 

Information Collection Request (ICR) 

document prepared by EPA has been 

assigned EPA ICR number 1230.18. 

Certain records and reports are 

necessary for the State or local agency 

(or the EPA Administrator in nondelegated areas), for example, to: (1) 

Confirm the compliance status of 

stationary sources, identify any 

stationary sources not subject to the 

standards, and identify stationary 

sources subject to the rules; and (2) 

ensure that the stationary source control 

requirements are being achieved. The 

information would be used by the EPA 

or State enforcement personnel to (1) 

identify stationary sources subject to the 

rules, (2) ensure that appropriate control 

technology is being properly applied, 

and (3) ensure that the emission control 

devices are being properly operated and 

maintained on a continuous basis. 

Based on the reported information, the 

State, local, or tribal agency can decide 

which plants, records, or processes 

should be inspected. 

The proposed rule would reduce 

burden for owners and operators of 

major stationary sources. While we do 

not expect a change in the number of 

permit actions due to the proposed 

changes, we expect the proposed rule 

would simplify applicability 

determinations, eliminate the burden of 

projecting future emissions and 

distinguishing between emissions 

increases caused by the change from 

those due solely to demand growth, and 

reduce recordkeeping and reporting 

burdens. Over the 3-year period covered 

by the ICR, we estimate an average 

annual reduction in burden of about 

5,870 hours and $462,000 for all 

industry entities that would be affected 

by the proposed rule. For the same 

reasons, we also expect the proposed 

rule to reduce burden for State and local 

authorities reviewing permits when 

fully implemented. However, there 

would be a one-time, additional burden 

for State and local agencies to revise 

their SIPs to incorporate the proposed 

changes. We estimate this one-time 

burden to be about 2,240 annual hours 

and $83,000 for all State and local 

reviewing authorities that would be 

affected by this proposed rule. 

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 purpose of 

responding to the information 

collection; adjust existing ways to 

comply with any previously applicable 

61102 Federal Register / Vol. 70, No. 202 / Thursday, October 20, 2005 / Proposed Rules 

instructions and requirements; train 

personnel to respond to a collection of 

information; search existing 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 OMB 

control number. The OMB control 

numbers for EPA’s regulations are listed 

in 40 CFR part 9 and 48 CFR chapter 15. 

We will continue to present OMB 

control numbers in a consolidated table 

format to be codified in 40 CFR part 9 

of the Agency’s regulations, and in each 

CFR volume containing EPA 

regulations. The table lists the section 

numbers with reporting and 

recordkeeping requirements, and the 

current OMB control numbers. This 

listing of the OMB control numbers and 

their subsequent codification in the CFR 

satisfies the requirements of the 

Paperwork Reduction Act (44 U.S.C. 

3501 et seq.) and OMB’s implementing 

regulations at 5 CFR part 1320. 

To comment on the Agency’s need for 

this information, the accuracy of the 

provided burden estimates, and any 

suggested methods for minimizine 

respondent burden, including use of 

automated collection techniques, EPA 

has established a public docket for this 

rule, which includes this ICR, under 

Docket ID number OAR–2005–1064. 

Submit any comments related to the ICR 

for this proposed rule to EPA and OMB. 

See ADDRESSES section at the beginning 

of this notice for where to submit 

comments to EPA. Send comments to 

OMB at the Office of Information and 

Regulatory Affairs, Office of 

Management and Budget, 725 17th 

Street, NW., Washington, DC 20503, 

Attention: Desk Officer for EPA. Since 

OMB is required to make a decision 

concerning the ICR between 30 and 60 

days after October 20, 2005, a comment 

to OMB is best assured of having its full 

effect if OMB receives it by November 

21, 2005. The final rule will respond to 

any OMB or public comments on the 

information collection requirements 

contained in this proposal. 

C. Regulatory Flexibility Act (RFA) 

The 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 notice on small entities, small 

entity is defined as: (1) A small business 

that is a small industrial entity as 

defined in the U.S. Small Business 

Administration (SBA) size standards. 

(See 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; or (3) a 

small organization that is any not-forprofit enterprise that is independently 

owned and operated and is not 

dominant in its field. 

After considering the economic 

impacts of today’s notice on small 

entities, I certify that this action will not 

have a significant economic impact on 

a substantial number of small entities. 

In determining whether a rule has a 

significant economic impact on a 

substantial number of small entities, the 

impact of concern is any significant 

adverse economic impact on small 

entities, since the primary purpose of 

the regulatory flexibility analyses is to 

identify and address regulatory 

alternatives ‘‘which minimize any 

significant economic impact of the 

proposed rule on small entities.’’ 5 

U.S.C. sections 603 and 604. Thus, an 

agency may certify that a rule will not 

have a significant economic impact on 

a substantial number of small entities if 

the rule relieves regulatory burden, or 

otherwise has a positive economic 

effect, on all of the small entities subject 

to the rule. 

We believe that today’s proposed rule 

changes will relieve the regulatory 

burden associated with the major NSR 

program for all EGUs, including any 

EGUs that are small businesses. This is 

because the proposed rule would 

simplify applicability determinations, 

eliminate the burden of projecting 

future emissions and distinguishing 

between emissions increases caused by 

the change from those due solely to 

demand growth, and by reducing 

recordkeeping and reporting burdens. 

As a result, the program changes 

provided in the proposed rule are not 

expected to result in any increases in 

expenditure by any small entity. 

We have therefore concluded that 

today’s proposed rule would relieve 

regulatory burden for all small entities. 

We continue to be interested in the 

potential impacts of the proposed rule 

on small entities and welcome 

comments on issues related to such 

impacts. 

D. Unfunded Mandates Reform Act 

Title II of the Unfunded Mandates 

Reform Act of 1995 (UMRA), Pub. L. 

104–4, establishes requirements for 

Federal agencies to assess the effects of 

their regulatory actions on State, local, 

and tribal governments and the private 

sector. Under section 202 of the UMRA, 

EPA generally must prepare a written 

statement, including a cost-benefit 

analysis, for proposed and final rules 

with ‘‘Federal mandates’’ that may 

result in expenditures to State, local, 

and tribal governments, in the aggregate, 

or to the private sector, of $100 million 

or more in any one year. Before 

promulgating an EPA rule for which a 

written statement is needed, section 205 

of the UMRA generally requires EPA to 

identify and consider a reasonable 

number of regulatory alternatives and 

adopt the least costly, most costeffective or least burdensome alternative 

that achieves the objectives of the rule. 

The provisions of section 205 do not 

apply when they are inconsistent with 

applicable law. Moreover, section 205 

allows EPA to adopt an alternative other 

than the least costly, most cost-effective 

or least burdensome alternative if the 

Administrator publishes with the final 

rule an explanation why that alternative 

was not adopted. Before EPA establishes 

any regulatory requirements that may 

significantly or uniquely affect small 

governments, including tribal 

governments, it must have developed 

under section 203 of the UMRA a small 

government agency plan. The plan must 

provide for notifying potentially 

affected small governments, enabling 

officials of affected small governments 

to have meaningful and timely input in 

the development of EPA regulatory 

proposals with significant Federal 

intergovernmental mandates, and 

informing, educating, and advising 

small governments on compliance with 

the regulatory requirements. 

We have determined that this rule 

would not contain a Federal mandate 

that would result in expenditures of 

$100 million or more by State, local, 

and tribal governments, in the aggregate, 

or the private sector in any 1 year. 

Although initially these changes are 

expected to result in a small increase in 

the burden imposed upon reviewing 

authorities in order for them to be 

included in the State’s SIP, these 

revisions would ultimately simplify 

applicability determinations, eliminate 

the burden of reviewing projected future 

emissions and distinguishing between 

emissions increases caused by the 

change from those due solely to demand 

growth, and reduce the burden 

associated with making compliance 

Federal Register / Vol. 70, No. 202 / Thursday, October 20, 2005 / Proposed Rules 61103 

determinations. Thus, today’s action is 

not subject to the requirements of 

sections 202 and 205 of the UMRA. 

For the same reasons stated above, we 

have determined that today’s notice 

contains no regulatory requirements that 

might significantly or uniquely affect 

small governments. Thus, today’s action 

is not subject to the requirements of 

section 203 of the UMRA. 

E. Executive Order 13132—Federalism 

Executive Order 13132, entitled 

‘‘Federalism’’ (64 FR 43255, August 10, 

1999), 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.’’

This proposed rule does not have 

federalism implications. It 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. We estimate an 

one-time burden of approximately 2,240 

hours and $83,000 for State agencies to 

revise their SIPs to include the proposed 

regulations. However, these revisions 

would ultimately simplify applicability 

determinations, eliminate the burden of 

reviewing projected future emissions 

and distinguishing between emissions 

increases caused by the change from 

those due solely to demand growth, and 

reduce the burden associated with 

making compliance determinations. 

This will in turn reduce the overall 

burden of the program. Thus, Executive 

Order 13132 does not apply to this rule. 

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.’’ This proposed rule does 

not have tribal implications, as specified 

in Executive Order 13175. There are no 

Tribal authorities currently issuing 

major NSR permits. To the extent that 

today’s proposed rule may apply in the 

future to any EGU that may locate on 

tribal lands, tribal officials are afforded 

the opportunity to comment on tribal 

implications in today’s notice. Thus, 

Executive Order 13175 does not apply 

to this rule. 

Although Executive Order 13175 does 

not apply to this proposed rule, EPA 

specifically solicits comment on this 

proposed rule from tribal officials. We 

will also consult with tribal officials, 

including officials of the Navaho Nation 

lands on which Navajo Power Plant and 

Four Corners Generating Plant are 

located, before promulgating the final 

regulations. 

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 

EPA has 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. 

EPA interprets Executive Order 13045 

as applying only to those regulatory 

actions that are based on health or safety 

risks, such that the analysis required 

under section 5–501 of the Order has 

the potential to influence the regulation. 

This rule is not subject to Executive 

Order 13045, because we do not have 

reason to believe the environmental 

health or safety risks addressed by this 

action present a disproportionate risk to 

children. We believe that, based on our 

analysis of electric utilities, this rule as 

a whole will result in equal 

environmental protection to that 

currently provided by the existing 

regulations, and do so in a more 

streamlined and effective manner. 

H. Executive Order 13211—Actions 

Concerning Regulations That 

Significantly Affect Energy Supply, 

Distribution, or Use 

This rule is not a ‘‘significant energy 

action’’ as defined in Executive Order 

13211, ‘‘Actions Concerning Regulations 

That Significantly Affect Energy Supply, 

Distribution, or Use’’ [66 FR 28355 (May 

22, 2001)] because it is not likely to 

have a significant adverse effect on the 

supply, distribution, or use of energy. In 

fact, this rule improves owner/operator 

flexibility concerning the supply, 

distribution, and use of energy. 

Specifically, the proposed rule would 

increase owner/operators’ ability to 

utilize existing capacity at EGUs. 

I. National Technology Transfer and 

Advancement Act 

Section 12(d) of the National 

Technology Transfer and Advancement 

Act of 1995 (‘‘NTTAA’’), Public Law No. 

104–113, 12(d) (15 U.S.C. 272 note) 

directs EPA to use voluntary consensus 

standards in its regulatory activities 

unless to do so would be inconsistent 

with applicable law or otherwise 

impractical. Voluntary consensus 

standards are technical standards (for 

example, materials specifications, test 

methods, sampling procedures, and 

business practices) that are developed or 

adopted by voluntary consensus 

standards bodies. The NTTAA directs 

EPA to provide Congress, through OMB, 

explanations when the Agency decides 

not to use available and applicable 

voluntary consensus standards. 

Today’s proposed rule does not 

involve technical standards. Therefore, 

EPA is not considering the use of any 

voluntary consensus standards. 

List of Subjects in 40 CFR Parts 51 and 

52 

Environmental protection, 

Administrative practice and procedure, 

Air pollution control, Electric 

Generating Unit, BACT, LAER, Nitrogen 

oxides, Sulfur dioxide, BART, Clean Air 

Interstate Rule. 

Dated: October 13, 2005. 

Stephen L. Johnson, 

Administrator. 

[FR Doc. 05–20983 Filed 10–19–05; 8:45 am] 

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