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50172 Federal Register / Vol. 56, No. 192 / Thursday, October 3, 1991 / Rules and Regulations

ENVIRONMENTAL PROTECTION

AGENCY

40 CFR Part 52

IAD-FRL-4018-5]

Approval and Promulgation of

Implementation Plans: Revision of the

Visibility FIP for Arizona

AGENCY: U.S. Environmental Protection

Agency (EPA).

ACTION: Final rule.

SUMMARY: This notice revises the

Federal implementation plan (FIP) for

the State of Arizona to include a sulfur

dioxide (SO2) emission limit of 42

nanograms per Joule (ng/J) [0.10 pound

per million British thermal units (lb/

MMBtu)], heat input for the Navajo

Generating Station (NGS) to remedy

visibility impairment in the Grand

Canyon National Park (GCNP).

Compliance with this emission limit will

be phased-in by unit in 1997, 1998, and

1999 and determined on a plant-wide

annual rolling average basis. In

addition, NGS will be required to

reschedule its maintenance such that 6

unit-weeks of maintenance will be

perfoi'med during the winter months.

This action is taken pursuant to

sections 169A and 110(c) of the Clean

Air Act (Act), 42 U.S.C. sections 7491

and 7410(c), which require EPA, upon

default by a State, to take appropriate

measures to remedy certain certified

visibility impairments in mandatory

Class I areas. The timing of today's

action is in accordance with the revised

settlement agreement between EPA and

Environmental Defense Fund (EDF) in

EDF v. Reilly, No. C82-6850 RPA (N.D.

Cal.).

EFFECTIVE DATE: This action will be

effective on November 4, 1991.

ADDRESSES: Docket: Pursuant to section

307(d)(1)(B) of the Act, 42 U.S.C.

7607(d)(1)(B), this action is subject to the

procedural requirements of section

307(d). Therefore, EPA established

Docket A-89-02A for this action.

Materials related to the development of

this notice have been placed in this

docket. Materials related to EPA's

preliminary attribution determination

(54 FR 36948 (September 5, 1989)) have

been placed in Docket A-89-02, For

background information, materials

related to the development of the

visibility protection program (40 CFR

51.300 et seq.) are available in Docket

A-79--40. Also, materials related to the

development of the visibility new source

review (NSR) and visibility monitoring

strategies are available in Docket A-84-

32. Materials related to the visibility

long-term strategy, implementation of

control strategy, and integral vista

program are available in Docket A-85-

26. All dockets are available for public

inspection and copying between 8:30

a.m. to 12 noon and 1:30 p.m. to 3:30

p.m., Monday through Friday, at EPA's

Central Docket Section, Office of the

General Counsel, room 1500, 401 M

Street, SW., Washington, DC 20460. A

reasonable fee may be charged for

copies.

FOR FURTHER INFORMATION CONTACT.

Mr. David H. Stonefield, U.S.

Environmental Protection Agency,

Office of Air Quality Planning and

Standards (MD-15), Research Triangle

Park, North Carolina 27711, (919] 541-

5350 or FTS 629-5350.

SUPPLEMENTARY INFORMATION:

I. Background

A. Regulatory Requirements

Section 169A of the Act, 42 U.S.C.

7491, sets as a national goal "the

prevention of any future,.and the

remedying of any existing, impairment

of visibility in mandatory Class I

Federal areas which impairment results

from manmade air pollution."

Mandatory Class I Federal areas are

certain national parks, wildernesses,

and international parks as described in

section 162(a) of the Act, 42 U.S.C.

7472(a). Section 169A requires that EPA

promulgate regulations to assure

reasonable progress toward meeting the

national goal for mandatory Class I

Federal areas where EPA has

determined that visibility is an

important value. On November 30, 1979,

EPA identified 156 such areas, including

the GCNP in Arizona, where visibility is

an important air quality-related value

(44 FR 69122). Section 169A specifically

requires EPA to promulgate regulations

requiring States to amend their State

implementatioh plans (SIP's) to provide

reasonable progress toward meeting the

national goal for the 156 areas. On

December 2, 1980, EPA promulgated the

required visibility regulations (45 FR

80084, codified at 40 CFR 51.300 et seq.).

The visibility regulations require the 36

States listed in section 51.300(b),

including Arizona, to:

1. Coordinate SIP development with

the appropriate Federal land managers

(FLM's).

2. Develop programs to assess and

remedy Phase I visibility impairment

from existing sources and to prevent

visibility impairment from new sources.

3. Develop a long-term (10 to 15 years)

strategy to address, among other things,

Phase I visibility impairment to assure

reasonable progress toward the national

goal.

4. Develop a visibility monitoring

strategy to collect information on

visibility conditions.

5. Consider in all aspects of visibility

protection any "integral vistas"

(important views of landmarks or

panoramas that extend outside of the

boundaries of the Class I area)

identified by the FLM's as critical to the

visitors' enjoyment of the Class I areas.

The affected States were required to

submit revised SIP's satisfying these

provisions by September 2, 1981 (see 45

FR 80091, codified at 40 CFR

51.302(a)(1)).'

The second and third requirements

listed above are of particular relevance

to today's action. Pursuant to 40 CFR

51.302(c)(2), each affected State is

required to include in its SIP such

emission limitations, schedules of

compliance, and other measures as may

be necessary to make reasonable

progress toward the national visibility

goal. Under 40 CFR 51.302(c)(1), an FLM

may certify to a State that there exists

impairment of visibility in any

mandatory Class I Federal area. Such

impairment must be addressed in

accordance with 40 CFR 51.302(c) which

sets forth measures for achieving

reasonable progress, including best

available retrofit technology (BART)

and a long-term strategy (see 40 CFR

51.302(c) (1) and (2), section 169A(b)(2)

(A) and (B)). Pursuant to 40 CFR

51.302(c)(4)(i), where impairment is

certified at least 6 months prior to plan

submission, an affected State must

identify each existing stationary facility

which may "reasonably be anticipated

to cause or contribute" to any such

impairment which is "reasonably

attributable to that existing stationary

facility," and analyze for BART any

facility so identified. "Reasonably

attributable" impairment is impairment "attributable by visual observation or

any other technique the State deems

appropriate" (40 CFR 51.301(s)). Where a

I The EPA's 1980 regulations implementing the

statutory requirements of section 169A address

visibility impairment that is reasonably attributable

to a single source or small group of sources ("Phase

r, impairment) (see generally 45 FR 80084

(December 2. 1980)). Recognizing certain scientific

and technical limitations, EPA, in promulgating the

1980 regulations, deferred regulatory action on more .complex problems such as regional haze and urban

plumes." id. at 80086. Today, in accordance with the

1980 regulations, EPA is taking regulatory action to

remedy visibility impairment that is caused by NGS.

The EPA is in the process of establishing the Grand

Canyon Visibility Transport Commission as required by section 169B of the Act. The duties of

that commission include making recommendations

on "promulgation of regulations under section 169A

to address long-range strategies for addressing

regional haze which impairs visibility in * the

GCNP" (section 169B(d(21C}).
Federal Register / Vol. 56, No. 192 / Thursday, October 3, 1991 / Rules and Regulations 50173

State defaults on its obligations under

the visibility regulations, EPA may act in

place of the State pursuant to a FIP

under section 110(c) of the Act, 42 U.S.C.

7410(c), 2 and promulgate such limitation

and measures as are required to achieve

reasonable progress. In such cases, all of

the rights and duties that would

otherwise fall to the State accrue

instead to EPA.

The visibility regulations promulgated

at 40 CFR 51.302(c)(4)Xi) require that

once a Phase I impairment has been

certified, a State (or EPA if the State's

visibility protection program addressing

BART has not been approved, and EPA

is acting in its place) must analyze for

BART any specific existing stationary

facility it identifies as a "reasonably

attributable" source of the impairment.

Pursuant to section 169A(b) of the Act

(42 U.S.C. 7491(b)) and 40 CFR

51.302(c)(4)(iii), the emission limitation

representing BART for fossil fuel-fired

power plants with a generating capacity

in excess of 750 megawatts (MW) must

be determined pursuant to guidelines

promulgated by the Administrator. This

statutorily-required procedure for

conducting a BART analysis is found in

"Guidelines for Determining Best

Available Retrofit Technology Analysis

for Coal-Fired Power Plants and Other

Stationary Facilities" (EPA-450/3-80-

009b BART Guidelines). A copy of this

document may be found in Docket A89-02A.

In December 1982, environmental

groups, including EDF, filed a citizens,

suit in the United States District Court

for the Northern District of California

2 Section 110(c) requires EPA to promulgate FIP's

whenever a State fails to submit an implementation

plan (or portion thereof) which meets the

requirements of section 110, whenever the

Administrator determines that a plan (or portion) Is

not in accordance with the requirements of section

110, or whenever the State fails to revise its plan

within 60 days after notification by the

Administrator in accordance with section

During the House of Representatives'

consideration of the Conference Report on the 1977

Amendments to the Clean Air Act. Congressman

Rogers reiterated that the conferees had agreed that

EPA was to act where States failed to carry out

their duties in implementing the requirements of

section 169A. The pertinent part of Congressman

Rogers' statement is as follows:

'The conferees * * * rejected a motion to delete

EPA's supervisory role under section 110 to assure

that the required progress towards that goal [the

national visibility goal) will be achieved by the

revised State plan. If a State visibility protection

plan is not adequate to assure such progress, the

Administrator must disapprove that portion of the

SIP and promulgate a visibility protection plan

under section 110(c). Thus. visibility protection in

mandatory federal class I areas remains a national

commitment, which is nationally enforceable."

See Senate Comm. on Environment and Public

Works, 95th Cong. 2d. Sees. "A Legislative History of the Clean Air Act Amendment of 1977" No. 16,

vol. 3 at 311. 320-21 (Comm. Print 1978).

alleging that EPA had failed to perform

a nondiscretionary duty under section

110(c) of the Act, 42 U.S.C. 7410(c), to

promulgate visibility FIP's for the 35

States ' that, at that time, had failed to

submit SIP's to EPA as called for by the

1980 visibility regulations, EDF v. Reilly,

No. C82-6850 RPA (N.D. Cal.). The State

of Arizona was one of the 35 States that

failed to submit a revised SIP to EPA.

The EPA and the plaintiffs negotiated

a settlement agreement for the

remaining States which the court

approved by order on April 20, 1984. For

more information on details of the

provisions of the original settlement,

including a schedule of actions by EPA,

see EPA's announcement of the

agreement at 49 FR 20647 (May 16, 1984).

B. Settlement Agreement

To remedy the States' failure to

submit the necessary SIP revisions

during the time specified by the

regulations, the settlement agreement

replaced the original regulatory

deadlines for visibility SIP provisions

with a rulemaking schedule agreed to by

the parties and approved by the court.

This schedule required EPA to review

the existing SIP's to determine any

deficiencies, allow the States to cure

those deficiencies, and to promulgate

FIP's on a specified schedule for those

States that still did not submit visibility

SIP revisions to EPA. Specifically, the

first pert of the agreement required EPA

to promulgate FIP's which cover the

monitoring and NSR provisions of 40

CFR 51.305 and 51.307. The EPA

promu.gated its monitoring strategy for

23 States and its NSR provisions for 21

States, including Arizona, at 50 FR 28544

(July 12, 1985), 51 FR 5504 (February 1,

1986), and 51 FR 22937 (June 24, 1986). In

separate notices, EPA approved the

SIP's of the other States with respect to

monitoring and NSR.

The second part of the settlement

agreement required EPA to determine

the adequacy of the SIP's to meet the

remaining provisions of the visibility

regulations and gave the States until

December 1986 to submit additional

measures that would avoid the need for

a FIP. These provisions are the general

plan pr'ovisions for achieving reasonable

progress toward the national visibility

goal ircluding BART and other

implerientation control strategies

(§ 51.302), integral vista protection

(§ 51.302-307), and long-term strategies

(§ 51.306). The settlement agreement

requir .d EPA to promulgate FIP's to

5The State of Alaska had submitted a SIP which

was ap roved on July 5, 1983 at 48 FR 30623.

remedy any deficiencies on a specified

schedule.

Pursuant to 40 CFR 51.302(c)(1), on

November 14, 1985, the Department of

the Interior (DOI) certified the existence

of visibility impairment in all Class I

areas within its jurisdiction in the lower

48 States.

On January 23, 1986, EPA determined

that the SIP's of 32 States (including

Arizona) were deficient with respect to

the remaining visibility provisions (51

FR 3046) and offered the States an

opportunity to submit corrective SIP

revisions. Thereafter, EPA and the

plaintiffs negotiated revisions to the

settlement agreement which extended

the deadlines for State action or, if the

States failed to respond, Federal action

proposing FIP's to remedy these

deficiencies. The court approved these

revisions by its order of September 9,

1986. 4

On March 24, 1488, the DOI sent a

letter to EPA which supplemented its

earlier certification of visibility

impairment. The letter addressed the

GCNP and identified the NGS, a coalfired power plant located near Page,

Arizona, as a probable source of

impairment in this Class I area. A copy

of this letter may be found in Docket A89-02.

Thirty-two affected States failed to

submit visibility SIP revisions in

response to the notice of deficiency.

Consequently, in accordance with the

revised settlement agreement, on March

12, 1987 (52 FR 7802), EPA proposed to

disapprove the SIP's of 32 States,

including Arizona, for failing to meet the

remaining provisions of the visibility

regulations, including general plan

requirements to achieve reasonable

progress toward the national visibility

goal (which in turn includes BART, longterm strategies, and other control

strategies). Also in accordance with the

agreement, on November 24, 1987 (52 FR

45132), EPA took final action

disapproving the affected SIP's, again

including Arizona. In that action, EPA

also promulgated, as FIP measures

under section 110(c), general plan

requirements for these States. The EPA

also determined that BART was

unnecessary in 28 States because it

could not reasonably attribute the

visibility impairment of mandatory

Class I Federal areas in thene States to

specific sources or small groups of

sources. In addition, undar the revised

agreement, EPA deferred until August

31, 1988 a decision regarding the need

4 A copy of the settlement agreemnt and

revisions is available in Docket A-& -26 at the

address given at the beginning of this notice.
50174 Federal Register / Vol. 56, No. 192 / Thursday, October 3, 1991 / Rules and Regula,.ons

for BART or other control measures in

the FIP's for the States of Arizona,

Maine, Minnesota, and Utah to address

certified visibility impairments in seven

Class I areas in these States which

potentially could be reasonably

attributed to a specific source pending

acquisition and evaluation of additional

technical information regarding the

potential sources of impairment.

Because all of the additional

information needed by EPA was

forthcoming but still not available by

August 1988, the Agency sought and

received a second extension, until

August 31, 1989, of the deadline for

issuing a rulemaking proposal regarding

the need for BART or other control

measures to remedy visibility

impairments in three of the remaining

Class I areas (Moosehorn Wilderness,

GCNP, and Canyonlands National Park).

With regard to the Impairment in the

GCNP, EPA delayed action in order to

allow the National Park Service (NPS)

time to analyze the data from a 1987

winter visibility attribution study,

termed the Winter Haze Intensive

Tracer Experiment (WHITEX),

conducted in the Colorado Plateau

where the GCNP is located. In the

meantime, on May 19, 1989 (54 FR

21904), in accordance with the second

revision to the settlement agreement,

EPA promulgated final decisions

concerning certified visibility

impairments in four of the seven Class I

areas. Based on monitoring conducted in

these areas, EPA found that the

visibility impairments were not

reasonably attributable to any specific

source. Therefore, EPA determined that

it was not necessary to revise the FIP's

for the States of Maine, Minnesota, and

Arizona to include BART or other

control strategies to remedy

impairments in Roosevelt Campobello

International Park (Canada), Voyageurs

National Park (Minnesota), Saguaro

Wilderness (Arizona), and Petrified

Forest National Park (Arizona).

In April 1989, EPA received a draft

report on WHITEX from the NPS.5

Because of the delay in receiving this

report, EPA believed that it lacked

sufficient time to complete its analyses

and issue a proposed rule by the August

31, 1989 deadline. Accordingly, EPA and

EDF filed a joint motion to revise the

settlement agreement for a third time,

which was approved by order of the

court dated July 6, 1989. Under this

revision, there was no change in the

deadlines for proposed action regarding

Canyonlands National Park or

5 Maim. at al.. "The National Park Service Report

on WHITEX Draft Final Report" (April 7, 1989).

Moosehorn Wilderness. As to GCNP, the

third revision to the settlement

agreement divided EPA's duty into two

parts. The EPA would proceed, on a

preliminary basis, to issue a finding on

reasonably attributable impairment by

the August 31,1989 deadline. However,

if EPA did provisionally identify a

specific source of impairment, it would

solicit comments on that finding and

would have additional time to conduct a

BART analysis. The EPA was to issue a

rulemaking proposal on the need for

BART by February 1, 1990 unless, in

response to comments, EPA rejected its

proposed identification and instead

determined that BART was

unnecessary.

In accordance with the third revision

to the settlement agreement, EPA

published a notice of proposed

rulemaking on September 5, 1989 (54 FR

36948). Regarding Moosehorn

Wilderness, EPA identified a source of

the certified impairment but proposed

that BART was unnecessary because

the impairment would be adequately

remedied by the retirement of certain

existing emission units and the addition

of pollution controls on other units

pursuant to a permit issued under the

Act's prevention of signifigant

deterioration provisions. As to

Canyonlands National Park, EPA could

not reasonably attribute the certified

impairment to a specific source at that

time and so proposed that BART was

unnecessary. On June 13, 1990 (55 FR

24060), EPA issued final decisions that

BART was not necessary to address

impairment in either the Moosehorn

Wilderness or the Canyonlands

National Park.

Regarding the GCNP, in the

September 5, 1989 notice, EPA

preliminarily attributed several episodes

of wintertime visibility impairment to

emissions from the NGS. In that regard,

EPA reviewed the draft NPS report on

WHITEX and concurred with the

findings of the NPS. The EPA solicited

comments on the merits of its

preliminary attribution finding.

On November 28, 1989, the Salt River

Project Agricultural Improvement and

Power District (SRP), et al., and

Alabama Power Company, et al.,

intervenors in EDF v. Reilly, filed a

motion requesting a 1-year delay in the

rulemaking schedule so that, among

other things, the intervenors could

conduct their own studies of the

visibility impairment in the GCNP. By

order dated January 9, 1990, the court

granted the intervenors' motion to

extend the deadlines. This order set

February 1, 1991, as the new deadline

for EPA to propose whether or not to

require BART emission limits for the

NGS to remedy winter visibility

impairment. The order also extended the

deadline for final action on any proposal

regarding BART until October 1991 (6

months after the close of the comment

period)."

C. Navajo Generating Station

The NGS is a 2250,MW coal-fired

power plant located near Page, Arizona,

approximately 20 kilometers from the

northern boundary of the GCNP. The

NGS is a baseload generating station

consisting of three 750 MW units which

became operational between 1974 and

1976. The SRP is the operating agent for

NGS which is jointly owned by the

SRP,7 the Los Angeles Department of

Water and Power, the Arizona Public

Service Company, the Nevada Power

Company, and the Tucson Electric

Power Company. Existing pollution

control equipment at NGS includes

electrostatic precipitators for particulate

matter (PM) removal and specific burner

design for nitrogen oxides (NOX) control.

D. February 8,1991 Proposal

On February 8, 1991, EPA proposed to

revise the FIP for Arizona to include

emission limits to address the visibility

impairment observed in GCNP. The

following is a summary of the main

issues discussed in the proposal notice.

1. Emission Limitation

The EPA proposed to adopt a

continuous SO2 emission limitation of

0.30 lb/MMBtu. Compliance would be

determined on a 30-day rolling average

and would be phased in between 1995

and 1999. Because of the uncertainty in

determining the improvement in

visibility expected as a result of

reducing emissions at the NGS, EPA

solicited comments on three alternative

control strategies for NGS:

a. A continuous SO2 emission

limitation of 0.50 lb/MMBtu. Compliance

would be determined on a 30-day rolling

* The EDF has appealed the extension of

rulemaking deadlines in this case. EDFv. Reilly. No.

90-15264 (9th Cir.). That appeal Is pending. In a

Memorandum of Understanding (MOU) discussed

below, parties to this litigation have agreed, in light

of today's action, to petition (a) the Ninth Circuit to

vacate the judgment below and remand the matter

to the court below with instructions to dismiss and

(b) the District Court for the Northern District of

California to dismiss EDF v. Reilly. No. C82-6850.

7 The SRP owns 21.7 percent of the NGS project

for its own use and benefit, and 24.3 percent for the use and benefit of the United States in accordance

with the NGS project agreements. The term "NGS

participants" is used in this notice to refer to the

parties which have rights and responsibilities

associated with the operation of NGS and includes

the owners, the operators, and the U.S. Bureau of

Reclamation (for the United States).
Federal Register / Vol. 56, No. 192 1 Thursday, October 3, 1991' /,Rules and Regulations 50175 I III I

average and would be phased in

between 1995 and 1999.

b. A continuous SO2 emission

limitation of 0.10 lb/MMBtu. Compliance

would oe determined on a 30-day rolling

average and would be phased in

between 1995 and 1999.

c. A January 10, 1991 proposal

submitted by SRP under which it would

test alternative control technologies, and

if one of the technologies met a

minimum removal efficiency at a set

cost, the NGS would install that.

technology and operate it in the

wintertime. If none of the technologies

met the test criteria, NGS would reduce

its emissions by 70 percent (0.30 lb/

MMBtu emission limit) measured on an

annual basis by the year 2000.

In addition, EPA requested comment

on whether another emission limitation

or a different averaging period may be

more appropriate.

2. Attribution

As part of the February 8, 1991

proposal, EPA reopened the comment

period on its September 5, 1989

preliminary finding that several

episodes of wintertime impairment in

the GCNP was reasonably attributable

to NGS. The EPA noted both in the

September 1989 and the February 1991

notices that the finding was not based

on any single analytical technique in the

NPS report on WHITEX, but rather on

the collection of techniques performed

by the NPS using WHITEX and other

data. In detail, EPA explained that all of

the techniques used by the NPS support

the conclusion that NGS is a source of

visibility impairment in the Grand

Canyon during certain wintertime

episodes. Also, in some detail, EPA

discussed the National Academy of

Science's (NAS'] review of the WHITEX

study and discussed other visibility

studies performed subsequent to

WHITEX.

The National Research Council of the

NAS reviewed and reported on the

scientific methods used in the WHITEX

report. The NAS report, entitled "Haze

in the Grand Canyon: An Evaluation of

the Winter Haze Intensive Tracer

Experiment" (October 1990), contained a

qualitative assessment of WHITEX

which supported EPA's finding that, on

some days, NGS is a source of visibility

impairment in the GCNP.8 Further, the

8 The report found, for example, that the detection

at Hopi Point (GCNP) of the unique tracer released

from NGS in the WHITEX study "is an

unambiguous indicator that air parcels containing

NGS emissions did impinge on the GCNP on several

occasions." Executive Summary at p. 3.

NAS found that the "rate of SO2

emissions from NGS is easily large

enough to serve as the source of the

sulfur measured in the GCNP." 9

However, the report also found that the

data base and data analyses techniques

in the WHITEX report were not,

standing alone, sufficient to ascertain

the quantitative NGS contribution to

haze at any given time. The NAS report

has been placed in the rulemaking

docket. 1

0

The SRP has conducted another study

known as the Navajo Generating Station

Visibility Study (NGSVS). That study

attempted to measure the degree of

contribution by the NGS to visibility

impairment in the GCNP during the

1989-1990 winter season and to assess

the levl of improvement expected as a

result of reducing the SO emissions at

NGS. The SRP submitted a draft report

describing that study and its results I

during the public comment period on

EPA's February 8, 1991 proposal. The

NGSVS concluded that NGS emissions

were present at Hopi Point less

frequently than during the WHITEX

period. In addition, the NGSVS

concluded that on days when NGS

emissions were present, visibility

impairment at Hopi Point associated

with those emissions was substantially

less then the amount calculated in the

NPS report on WHITEX. However,

results indicate that NGS was

responsible for a significant quantity of

sulfate and haze during specific

visibility impairment episodes in GCNP.

3. BARr Analysis

In light of its attribution finding, EPA

conducted an analysis in accordance

with the BART Guidelines (EPA-450/3-

80-00b) and 40 CFR 51.301(c)(4)(iii). 12

That analysis included consideration of

the following: the costs of compliance,

the energy and non-air quality

environmental impacts, any existing

pollution control technology in use at

the facility, the remaining useful life of

the source, and the degree of

improvement in visibility anticipated to

result from application of controls.

Considering the requirements found in

the BART Guidelines, EPA divided its

analysis into two major parts. In the first

9 The NAS report at p. 33.

10 Additional copies of this report are available

from the National Academy Press, 2101 Constitution

Avenue. NW., Washington, DC 20418.

I ISonoma Technology, Inc.., "Navajo Generating

Station Visibility Study," Draft Number 2, April 16,

1991.

"2 U.S. EPA, "Draft Report on Best Available

Retrofit Technology (BARTJ Analysis for the Navajo

Generatig Station in Page, Arizona," January 1990.

A copy of this document has been placed In Docket

A-89-02A.

part, EPA Identified the SO emission

controls that are readily available to the

source, the costs of such controls, and

other impacts of installing and operating

the controls. In the second part of the

analysis, EPA attempted to define the

source-impairment relationship which

was then used to predict the

improvements in visual air quality that

can reasonably be expected to occur as

a result of installing and operating the

controls defined in the control

technology analysis. Because EPA was

faced with some uncertainties in each of

the parts of the analysis, EPA bounded

its results by giving low and high

estimates. A detailed discussion of this

analysis for NGS was provided in EPA's

February 8, 1991 proposal.

To estimate the cost of controlling the

SO2 emissions at NGS, EPA used the

Integrated Air Pollution Control System

(LAPCS) cost model to predict the

capital and operating cost estimates for

0.10, 0.30, and 0.50 lb/MNIBtu control

levels. 13 The results from the IAPCS

indicated that wet flue gas

desulfurization (FGD) achieving a 0.30

lb/MMBtu emission limit for all three

units, the control level that was

proposed by EPA, was estimated to

have total capital cost requirements of

between $245.9 million and $402 million

with total levelized annual costs

(including amortized capital, Interest,

operating, and maintenance costs)

estimated to be between $91.9 million

and $128.3 million.1 4

In its February 8, 1991 proposal, EPA

also estimated the potential costs to

residential electricity customers

serviced by the NGS participnts as

well as the potential costs to Central

Arizona Project (CAP) customers.

One of the more complicated tasks in

the BART analysis was defining the

relationship between the SO2 emissions

at NGS and the visibility impairing

sulfate in the GCNP. This relationship

had to be addressed in order to estimate

the degree of improvement in visibility

that could be anticipated to result from

the use of the alternative SQ, control

systems. Because of the complex terrain

in and around the GCNP, EPA defined

the source/impairment relationship

using the ratio of SO emisslons at NGS

to sulfate in the GCNP attributable to

NGS as found in the final WHITEX

report. Using this ratio, EPA then

applied a linear rollback model.

However, in light of the uncertainties

IS Integrated Air Pollution Control System

Costing Program, Version 3.0, copyright PEI and

Associates, Inc., 1989.

14 All dollar amounts w"ere measured in 1988

dollars.
50176 Federal Register / Vol. 56, No. 192 / Thursday, October 3, 1991 / Rules and Regulations

surrounding these analyses EPA

considered a broad range of sourceimpairment relationships. In addition,

EPA developed and applied a

nonlinearity factor to the rollback model

to estimate the improvements in

visibility that would result from

reductions in SO2 .

Because no single standard method

exists for measuring improvements in

visibility, the EPA employed two of the

most widely used techniques to define

the improvements in Visibility expected

to occur in the GCNP. One of the ,

methods used to estimate the visibility

improvements in the GCNP was

analyzing the changes in contrast

expected to occur as a result of reducing

SO2 emissions at NGS. The EPA stated

in the proposal that this method is

particularly relevant because human

observers use contrast to make

judgments of how atmospheric clarity

changes with pollutant concentration.

The contrast is defined as the percent

difference between the brightness of a

scenic element and its background. The

second technique was to analyze the

seasonal average visual range change

(see 56 FR 5182 Table 1].

Although not specifically addressed in

the BART analysis, the proposal noted

that EPA suspected that NGS emissions

may contribute to visibility impairment

in the GCNP during other seasons of the

year and in other Class I areas in the

region. Thus, EPA sought comment on

any other potential visibility

impairments caused by NGS.

The EPA also noted in the proposal

that it was not required as a part of its

analysis to estimate monetary benefits

associated with improving visibility in

the GCNP. However, EPA evaluated the

monetary benefits in developing a part

of the preliminary Regulatory Impact

Analysis (RIA) (as required by

Executive Order 12291) for the proposed

rule.

4. Control of Particulate Matter and

Nitrogen Oxides

In the February 8. 1991 proposal, EPA

noted that two other pollutants emitted

by NGS, NO. and PM, are known to

contribute to visibility impairments in

some circumstances.' 5 The current

emissions of NO. and PM from NGS

were not identified as significantly

contributing to the visibility impairment

in the Grand Canyon. However, EPA

expressed concern based upon its

technical judgment regarding the

behavior of the pollutants as potential

contributors to visibility impairment as

a general matter, upon the amount of the

'5 See. e.g., BART Guidelines at p. 12-13.

pollutants emitted by NGS, upon the

proximity of NGS to the GCNP, and

upon the characteristics of the NGS

plume, as shown by WHITEX and other

studies, that increased emissions of

these pollutants could result in

impairment in the GCNP. The EPA noted

that although the.NGS is not subject to

any NO. emission limitations, SRP has

stated that NGS currently emits NO. at

a rate of 0.4 to 0.5 lb/MMBtu. Therefore,

EPA proposed an NO, emission limit

consistent with NGS' existing emission

rate, as well as the rate at other similar

plants, of 0.5 lb/MMBtu.

The EPA noted that PM emissions for

the NGS are currently limited in two

ways. The Arizona SIP has both an

emission rate limitation of 0.06 lb/

MMBtu and an opacity limit of 40

percent for NGS. The SRP has stated

that NGS currently emits PM at a rate of

0.03 lb/MMBtu with an opacity of

between 10 and 15 percent. Thus, the

opacity limit of 40 percent is well above

the NGS existing emissions. Therefore,

EPA proposed a 20 percent opacity

limitation consistent with current NGS

emissions in order to preclude any

visibility deterioration that would be

caused by an increase in PM emissions.

The EPA requested comments on

whether NO. and PM emission limits

would be appropriate for NGS.

5. Compliance Schedule

The EPA proposed to require that the

emission limitation be achieved in three

phases. Specifically, EPA proposed that

the final emission limitation would need

to be met on one unit by January 1, 1995;

on two units by January 1, 1997; and on

all three units by January 1, 1999. The

EPA solicited comments on whether the

phased-in compliance schedule

proposed was appropriate as a matter of

law or policy, and, as noted, requested

comment on the January 1991 SRP

proposal that a final emission limitation

not become effective before January 1,

2000.

6. Use of Seasonal Controls

Part of the SRP proposal called for the

use of seasonal controls. Therefore, EPA

solicited comment on the use of

seasonal controls. In the February 8,

1991 notice, EPA noted that such

controls would have to be both

technically and legally justified before

they could be used.

7. Other Issues

In the February 8, 1991 propo al, EPA

also specifically solicited comments on

the following:

a. Use of continuous emission

monitoring systems for compliance

determinations.

b. Plant-wide averaging of the

emission limitations.

c. Other available technologies which

can reduce SO2 emissions at NGS to

achieve the proposed or alternative

limits and which may require less

capital investment and/or operating

expenses than those technologies.

evaluated in the BART analysis.

In addition to soliciting written

comments during the comment period,

EPA held a public hearing on March 18

and 19, 1991 in Phoenix, Arizona. A copy

of the transcript of the hearing is in

Docket A-89-02A. As a result of the

comment period and public hearing,

EPA received over 400 comments on its

proposal. All the comments have been

placed in Docket A-89-02A.

Because of the differences in technical

opinions expressed and data analyses

submitted to EPA during the comment

period, EPA sponsored a technical

review meeting on April 25 and 26, 1991.

The EPA invited the NGS participants

and the environmental groups who

submitted technical information to EPA

to send technical representatives to the

meeting to discuss the interpretation of

the available data. The meeting was

open to the public, and a summary of

that meeting is included in Docket A-89-

02A.

E. New Information After the Close of

the Initial Comment Period

After the comment period closed on

April 19, 1991, at the recommendation of

EPA, representatives of SRP, Grand

Canyon Trust (GCT), and EDF met to

discuss alternative approaches to EPA's

February 8, 1991 proposal. In August

1991, the outside parties reached

agreement and together recommended

that EPA adopt an alternative control

for NGS consisting of a 0.10 lb/MMBtu

SO2 emission limitation (approximate to

a 90 percent control level) based on a

rolling annual average and phased inby

unit in November 1997, November 1998,

and August 1999. In addition, under the

agreement, NGS would shift its

maintenance schedule- such that 6 unitweeks of planned maintenance would

occur between November 1 and March

15 each year. Under specific conditions,

the Administrator of EPA may allow

NGS to shift the maintenance schedule

outside of that period or not to conduct

scheduled maintenance in a given year.

Representatives of EPA participated

in many of the meetings with the parties

and provided technical assistance.

Representatives of the State of Arizona

also attended several of the meetings

and provided additional technical

support. New technical materials and

cost information, including adjustments
Federal Register / Vol. 56, No. 192 / Thursday, October 3, 1991 / Rules and Regulations 50177

of the potential control costs, were

exchanged between the parties and

EPA. Summaries of the meetings and

significant conversations in which EPA was involved and copies of the new

material and information which were

submitted to or developed by EPA have

been included in Docket A-89-02A.

The outside parties memorialized their

agreement in an MOU which they

submitted to EPA along with

recommended regulatory requirements

for EPA's final rulemaking action. The

SRP estimated (in 1992 dollars) a capital

cost of $430 million and a total levelized

annual cost of $89.6 million for the

parties' recommended alternative. In

comparison, SRP estimated a capital

cost of $510 million and a total levelized

annual cost of $106 million to meet the

alternative EPA proposed in February

1991.

Noting that the alternative

incorporated in the MOU would provide

more visibility protection for the GCNP

at a lower cost for NGS and its

customers, EPA, on August 8, 1991,

reopened. the comment period on its

February 8, 1991 proposed action (56 FR

38399, August 13, 1991). In the notice,

EPA stated that it was giving serious

consideration to the control option

recommended by the outside parties and

incorporated in an appendix to the

notice a memorandum from EPA's

Office of General Counsel concluding

that the outside parties' legal rationale

in support of their recommended control

option was meritorious.

The EPA reopened the comment

period until September 9, 1991. Where

addresses were available, commenters

on the February 8, 1991 proposal were

notified by mail of the reopened

comment period in order to facilitate

their ability to comment.

The EPA received 21 comments during

the supplemental comment period.

Eighteen of the commenters supported

the alternative incorporated in the

MOU, and three opposed it. The SRP,

GCT, EDF, the Wilderness Society, the

National Wildlife Federation, and the

Sierra Club conditionally withdrew their

prior comments which were inconsistent

with the MOU and associated

documents.

II. Today's Action

In today's action EPA is promulgating

its final determination on the attribution

to NGS of certain visibility impairment

episodes in GCNP and is promulgating

Federal revisions to the visibility

implementation plan for Arizona to

address those impairment episodes. As

discussed below, EPA has concluded

that certain visibility impairment

episodes in GCNP are traceable to NGS

and that NGS is a dominant contributor

to certain visibility impairment

episodes. The EPA finds today that a

0.10 lb/MMBtu SO2 emission limitation

(appro imately a 90 percent emission

reduction] based on a rolling annual

averago and phased in by unit in

November 1997, November 1998, and

August 1999 in addition to scheduled

winter maintenance at NGS affords

greater visibility improvement than the

alternative advanced in EPA's February

1991 proposal. In particular, it will

reduce by two-thirds the amount of

pollution allowed under the proposed

rule. In addition, EPA finds that the final

rule will be significantly less costly than

the proposal. Consequently, EPA further

concludes that today's final action will

provide a greater degree of "reasonable

progress" toward the national goal of

remedying such impairment than would

be provided by the February 1991

proposal (see section 169A(b)(2) of the

Act, 42 U.S.C. 7491(b)(2)).

In EPA's August 1991 supplemental

notice requesting comment on the

rulemaking alternative largely adopted

in final form today, the Agency noted

that SRP, GCT, and EDF had

recommended that the legal rationale in

support of this alternative be the

requirement in section 169A(b)(2) of the

Act that implementation plan revisions

addressing visibility impairment achieve "reasorable progress" toward the

national visibility goal. The

supplemental notice also indicated that

EPA's Office of General Counsel had

reviewed the matter and concluded,

subject to any significant points that

may be raised in the reopened comment

period, that EPA could rely on the

reasonable progress provisions as the

basis for this alternative. No significant

adverse comments addressing the legal

basis were received. Accordingly, EPA

is adopting this rationale as discussed in

the supplemental notice.

Today's action is based upon the

material in the docket including EPA's

review and consideration of all

comments received during the comment

periods and at the public hearing. The

agreem mt between GCT, EDF, and SRP

and associated recommendations to

EPA, largely adopted in final form

today, also are in the docket. The EPA

has responded to all of the significant

comments received. Some responses are

provided later in today's notice.

Additionally, EPA has prepared a

document accompanying today's action,

"Response to Public Comments:

Proposed Revisions to Arizona Visibility

FIP for Navajo Generating Station,"

which responds to comments. This

document has been placed in Docket A89-02A.

A. Impairment Traceable to NGS

The EPA regulations promulgated on

December 2, 1980 "[rlequire the control

of impairment that can be traced to a

single existing stationary facility or

small group of existing stationary

facilities * * " (45 FR 80085).

Accordingly, EPA's regulations currently

cover existing sources where the

impairment Is traceable or "reasonably

attributable" to that source by visual

observation or other techniques deemed

appropriate by the State (Phase I

impairments). The EPA, acting for the

State under section 110(c) of the Act,

deems the techniques in the WHITEX

report, the NGSVS report, and other

data and analyses in the docket as

appropriate techniques for determining

reasonable attribution in this case for

the following reasons.

1. The unique tracers, deuterated

methane used in the WHITEX study and

perfluorocarbons used in the NGSVS,

injected into the emissions of NGS were

observed in substantial quantities at

Hopi Point during periods of episodic

visibility impairment.

2. The NGS Is the predominate source

of SO2 in the region.

3. SO2 released by a power plant

converts into sulfates through chemical

transformation in the atmosphere.

4. Meteorological data show that the

NGS plume easily can, and frequently

does, travel to GCNP.

5. The data and analyses in the docket

show that sulfates are the major

contributor to visibility impairment in

GCNP.

The EPA recognizes that NGS is not

the only source of visibility Impairment

at GCNP. Under the applicable statutory

provisions and regulations, however,

this is not determinative 16 (see

16 For example, under section 169A(bl(2) of the

Act, EPA is authorized to require visibility

implementation plans containing "emission limits,

schedules of compliance and other measures"

necessary to make reasonable progress toward

meeting the national visibility goal (see also 40 CFR

51.302(c)). The national visibility goal, in turn, calls

for the remedying of "any" manmade visibility

impairment in Class I areas (see section 169A(a)(1)

and 40 CFR 51.300(a)). As noted, EPA's regulations

implementing section 169A address visibility

impairment that is reasonably attributable to a single source or small group of sources and deferred

action on complex problems such as regional haze

(see generally, 45 FR 80084 (December 2,1980)).

Accordingly, as provided in the 1980 regulations, EPA may remedy through emission limits, schedules

of compliance, or other measures "any" visibility

impairment that is reasonably attributable to an existing stationary source or small group of sources (see also section 169A(c) of the Act and 50 CFR

51.303 (authorizing an exemption from control

requirements only where a plant does not "by itself or in combination with other sources" emit pollution "which may reasonably be anticipated to cause or Contin.ed
50178 Federal Register, !/ Vol. 56, No. 192 / Thursday, October 3, 1991 / Rules and Regulations

generally section 169A of the Act and 40

CFR 51.300 307). Moreover, even 'though

WHITEX and NGSVS contain some

scientific uncertainty, they are

technically'adequate for the regulatory

purposes at hand, as they both showed

that episodes of visibility impairment in

the GCNP can be reasonably attributed

to NGS. Accordingly, EPA concludes

today that certain visibility impairment

episodes of the GCNP are traceable to

NGS, and NGS is a dominant source of

those impairments. Notwithstanding

that other sources also may contribute

to those impairment episodes at GCNP,

EPA concludes that the addition of

emissions controls at NGS alone will

result in a significant improvement in

visibility at GCNP and will make "reasonable progress" toward meeting

the national visibility goal.

B. Control Technology

As part of the BART analysis 17 for

the February 1991 proposal, EPA

reviewed the available control

technologies as well as the

environmental impact of the use of such

technologies and the estimated costs of

installing and operating such equipment.

In today's action, EPA is not requiring

the use of any particular control

technology. Rather, EPA is establishing

an emission limitation and NGS has the

discretion to select and install the type

of control system which best meets its

needs. The available information in the

docket indicates that a wet FGD system

will be the economically proven control

technology for meeting the 0.10 lb/

MMBtu emission limitation at NGS.

As a result of new information

provided by SRP, EPA has revised and

updated its cost estimates for the

installation and operation of a wet FGD

system. The revised estimated capital

cost and total levelized annual cost to

meet the emission limitation EPA

proposed in February 1991, in 1992

dollars, are $510 million and $106

million, respectively. The estimated

capital cost and the total levelized

annual cost, in 1992 dollars, to meet the

emission limitation promulgated today,

are $430 million and $89.6 million,

respectively. Although not considered in

these cost estimates, EPA expects that

NGS will be able to recoup a portion of

the control costs by the sale of

marketable allowances which it will

receive as part of the allowance trading

contribute to significant impairment of visibility" in

any Class I area and affirms, by negative inference,

EPA's broad rulemaking authority)).

II U.S. EPA "Draft Report on Best Available

Retrofit Technology (BART) Analysis for: the Navajo

Generating Station in Page, Arizona." January 1990.

program that EPA is establishing under

Title IV of the Act.

Based on the information submitted

during the comment period by SRP and

Nevada Power Company (NPC) and the

above cost figures, EPA has estimated

that the average SRP and NPC

customers electric bills will increase

approximately $1.72 and $1.57 per

month, respectively. The customers of

the other utilities will have smaller

increases in their electric bills.

Commenters representing CAP

customers submitted Information

showing that water costs would

increase between $4.10 and $4.50 per

acre-foot based on EPA's February 1991

proposal. Since the cost figures for the

final action are lower than figures used

for these estimates, the increase in

water costs for the CAP customers is

expected to be less than $4.10 to $4.50

per acre-foot.

C. ControlStrategy

The EPA has adopted the combination

of a higher level of control; compliance

phased in by unit in 1997, 1998, and 1999;

an annual averaging period; and

scheduled winter maintenance as a

control strategy for NGS-the

alternative recommended to the EPA by

GCT, EDF, and SRP and identified in

EPA's August 1991 supplemental

notice-because it better addresses the

visibility effects of concern at a lower

cost than the proposal in EPA's

February 1991 notice. As highlighted

here and elsewhere, the control strategy

for NGS must be viewed as a whole and

not as severable parts. The EPA has

carefully weighed the relevant statutory

and regulatory considerations and

concluded that, taken in its entirety,

today's control strategy for NGS will

provide a greater degree of reasonable

progress toward the national goal at a

lower cost than EPA's February

proposal.

Essentially, the SO2 emissions from

NGS can contribute to two types of

visibility impairment. The major impact

of NGS is its dominant single source

impact during certain episodic visibility

impairment events, usually during the

winter. This impact has been observed

in winter studies (WHITEX and NGSVS)

as well as intense aerosol monitoring

within the canyon since 1988.!8 The

other concern addressed by the control

strategy in today's action is the less

intense impairments which occur at the

GCNP during seasons other than winter,

'= See Docket A-89- 2A specifically items IV-D164 and IV-D-375.

and occur at other nearby mandatory

Class I Federal areas. 19

The lower level of NGS S02 emissions

required by the 0.10 lb/MMBtu emission

limitation adopted today will afford

GCNP greater protection from episodic

events than an emission limitation

which allows significantly more SO2

emissions but is averaged over a shorter

period, such as the 0.30 lb/MMBtu

emission limitation proposed by EPA in

its February 1991 notice. The probability

of high NGS contribution to severe

episodic sulfate impairment events is

limited by the known design reliability

of current technologies which will

achieve the required 0.10 lb/MMBtu

emission limitation as well as the

scheduled winter maintenance

requirement. Thus, EPA believes that

despite the use of an annual averaging

time, the significant increase in control

level, expected reliability of the control

technology, and winter maintenance,

taken together will, for the most part,

prevent continuation of severe winter

episodes caused by NGS. At the same

time, the annual average lowers the

costs of compliance.

With respect to long-term potential

visibility impacts on the Golden Circle

area (the other Class I areas in the

Colorado Plateau), there is little doubt

that the lower emission rate over a

year's average will reduce NGS'

contribution to sulfate formation and

thus to sulfate-caused impairment more

than the control level proposed by EPA

in February 1991. Given NGS' central

location in relation to many Class I

areas, no matter what meteorological

events occur over a multi-year period, it

is likely that the sulfates originating

from NGS and transported to

surrounding Class I areas will be

reduced in proportion to the difference

in emission limitations, i.e., to one-third

of the levels in the February 1991

proposal.

Further, during the comment period on

the February 1991 proposal, EPA

received technical information '

suggesting that NGS contributes to

visibility impairment at GCNP in nonwinter seasons. 20 For the reasons just

discussed, the significantly lower

emission rate required today will, over

the long-term, curb NGS' contribution to

any visibility impairment in the GCNP

during seasons'other than winter to a

See, e.g.. Latimer, Douglas, "Haze Impacts on.

the Golden Circle of National Parks of Sulfur

Dioxide Emission from Navajo Generating Station:

Haze Puff Model Calculations for 19"8-90."

20 See Docket A-89-02A. item IV-D-171. and

seasonal control discussion below.
Federal Register / Vol. 56, No. 192 / Thursday, October 3, 1991 / Rules and Regulations 50179

greater degree than EPA's proposed

option.

Accordingly, the control scheme

adopted today for NGS is appropriate

for addressing the winter episodic

visibility impairment observed at the

GCNP and will also reduce any longterm, long-range impairment that NGS

emissions may contribute to during

other seasons at GCNP and at other

nearby Class I areas. 21

D. Emission Limitation

After reviewing the option

recommended by SRP, EDF, and GCT in

their MOU, EPA has determined that

such a control strategy will provide a

substantially greater degree of

emissions reduction, and a

correspondingly greater degree of

visibility improvement at a substantially

lower cost than the alternative proposed

in February 1991.22 For these reasons,

EPA also concludes that this option will

make additional reasonable progress

towards attainment of the national

visibility goal in comparison to the

February 1991 proposal. Thus, in today's

action EPA is promulgating an SO 2

emission limitation of 42 ng/J (0.10 lb/

MMBtu) heat input to be phased in by

unit in November 1997, November 1998,

and August 1999, with compliance

determined on a rolling annual average

basis.

Under today's final action, compliance

with the annual rolling average will be

determined by computing a weighted

plant-wide average of the SO2 emission

rate based on the daily SO2 emission

rate and the electric energy generated

21 As noted, section 169A of the Act establishes a

national visibility goal, not an air quality standard or a specific emission standard. While the objective

is to attain the goal. EPA's only mandate from

Congress is to make reasonable progress toward the

goal. For these reasons, EPA has more flexibility in

selecting a control strategy to meet the visibility

reasonable progress requirements than it does when a health-based air quality standard or specific

emission standard must be met. Thus, in

determining reasonable progress. EPA. by law, must consider the costs of compliance, the time necessary

for compliance, and the energy and non-air quality

environmental impacts of compliance (see section

169A(g)(I) of the Act). Consideration of the

pertinent statutory scheme and these specific

factors has informed several aspects of today's

action. Thus, for the policy and legal reasons stated, an annual rolling average emission limitation is

acceptable for this case. Moreover, while this

emission limitation is not expected to interfere with

attainment of any other requirement of the Act, its

adoption does not relieve NCS of any responsibility

for meeting any air quality standard, emission

standard, or other requirement of the Act. 22 In the August 1991 supplemental notice, EPA

published and requested comment on the parties' August 8, 1991 MOU and associated documents.

During the public comment period, the parties further clarified their agreement and submitted a revised version of their MOU and recommended

regulatory requirements to EPA. both documents

dated August 22.1991.

for the previous 365 "boiler operating

days" for each unit.2 3 The EPA was

concerned that the plant-wide average

reflectq the actual release of emissions

at the plant. Therefore, after discussion

with rupresentatives of SRP, GCT, and

EDF, EPA settled on a methodology that

appropriately weights the emissions

from each unit before calculation of the

plant-wide average. The EPA has used

the daily electric energy generated as a

weighting factor because that

information is readily available for each

unit and in this case is proportional to

the heat input to the boilers.

Specifically, compliance will be

determined as follows:

1. For each unit that has accumulated

at least 365 boiler operating days since

the passage of the starting date

applicable to it, the plant must measure

and record the SO 2 emission rate and

the electric energy generated on each

boiler operating day. The SO2 emission

rate will be computed using the data

from the required continuous emission

monitoring system for the unit and using

method 19, appendix A, 40 CFR part 60.

The electric energy generated, in

megawatt-hours, will be recorded from

the megawatt-hour meter for the unit.

2. For each unit, the previous 365

boiler operating days will be identified.

3. For each such day, the product of

the SOa emission rate and the electric

energy generated will be computed.

4. The 365 products for each unit will

be added.

5. The electric energy generated for

the 365 boiler operating days for each

unit will be added.

6. The sums of the product of the SO 2

emission rate and the electric energy

generated will be divided by the sum of

the electric energy generated to produce

a plant-wide weighted annual average

SO2 emission rate for comparison with

the emission limitation to determine

compliance.

Recording and computation of the

daily electric energy generated and SO 2

emission rates will commence on: 1. November 19, 1997 for the first unit,

2. November 19, 1998 for the second

unit.

3. August 19, 1999 for the third unit.

23 A "boiler operating day" is specific for each

steam-generating unit at NGS and Is defined as a 24-hour calendar day (the period of time between

12:01 a.m. and 12:00 midnight in Page, Arizona)

during which coal is combusted at that NGS unit for

the entire 24 hours. This definition is consistent with

the definition for "boiler operating day" in 40 CFR

60.41a: "u 24-hour period during which fossil fuel is

combustcd in a steam-generating unit for the entire

24 hours." The EPA notes that the set of previous

365 boiler operating days for each unit will be

unique to that unit and thus the same set of

calendar days probably will not be used for all

three units in determining compliance.

The NGS has the discretion to determine

which of its three units will be

controlled first and second.

In the discussion below, EPA has

recognized that certain difficulties

encountered during the first year of

operation of a control system or the

catastrophic failure of a control system

may, based on EPA's judgment, warrant

a limited exclusion from compliance

with the emission limitation, However,

as discussion below indicates, the

control system, as a general matter,

must be optimally operated consistent

with good engineering practices to keep

emissions at, or below, the emission

limitation.

For each unit, in determining

compliance with the annual average

emission limitation during the first year

of operation of the control equipment

installed to comply with this emission

limitation, periods during which one of

the following conditions are met will be

excluded:

1. Equipment or systems do not meet

designer's or manufacturer's

performance expectations.

2. Field installation including

engineering or construction precludes

equipment or systems from performing

as designed.

The periods during the first year to be

excluded will be determined by the

Administrator based on periodic reports

of compliance with this emission

limitation which must identify the times

proposed for exclusion and provide the

reasons for the exclusion, including the

reasons for the outage of the control

system. The report also must describe

the actions taken to avoid the outage, to

minimize Its duration, and to reduce SO2

emissions at the plant to the extent

practicable while the control system

was not fully operational. Whenever the

time to be excluded exceeds a

cumulative total of 30 days for any

control system, the NGS owner or

operator must file a report within 15

days addressing the history of, and

prognosis for, the performance of the

control equipment.

In addition to the foregoing, the

Administrator will exclude from the

compliance determination for a unit any

periods of emissions from a unit for

which the Administrator finds that the

control equipment is out of service

because of catastrophic failure of any

control system which occurred for

reasons beyond the control of the NGS

participants and operators and could not

have been prevented by good

engineering practice. The Administrator

will not exclude the period if the

equipment failure was a consequence ot

a lack of appropriate maintenance; of
50180 Federal Register / Vol. 56, No. 192 / Thursday, October 3, 1991 / Rules and Regulations

intentional or negligent conduct or

omissions of the NGS participants or

operators or the control system design,

construction, or operating contractors.

The 'final regulation requires that all

equipment needed to comply with this

regulation to be optimally operated

consistent with good engineering

practice to keep emissions at or below

the emission limitation. The regulation

also requires that following any control

system outages, the system must be

returned to full operation as

expeditiously as practicable.

The final regulation provides that

continuous emission monitors must be

installed to determine compliance with

the emission limitation. This equipment

must meet the specifications listed in

appendix B of 40 CFR part 60, the

quality assurance procedures in

appendix F of 40 CFR part 60, and the

requirements for estimating emission

rate in ng/J for lb/MMBtu) set out in

method 19, appendix A. 40 CFR part

60.24 The NGS is required to report

emissions and maintain records In

accordance with the procedures in 40

CFR 60.7. In addition. EPA is

establishing special notification

procedures when an outage of a control

system occurs. The NGS must notify the

Administrator by telephone or bywriting within one business day of any

outage of the control system needed for

compliance with the emission limitation

and must submit a follow-up written

report within 30 days of the repairs

stating how the repairs were

accomplished and justifying the amount

of time taken for the repairs.

In the February 1991 notice, EPA

proposed new NO. and opacity limits on

NGS emissions consistent with current

emission levels. These were proposed

due to a concern that certain SO2

emission control equipment would cause

increases in NO. and PM (which are

limited by opacity limitations) emissions

at NGS which could affect visibility in

GCNP. However, EPA does not have

any evidence at this time that NO, or

PM emissions from NGS contribute

I' For certain requirements in today's action (e.g..

monitoring. reporting. recordkeeping. etc.), EPA has

relied on Its regulations governing standards for

performance for new stationary sources. Those

regulations have been relied on because they

contain standardized procedures and requirements

which apply to coal-fired steam-generating units. In

addition. EPA has provided that the NGS owners or operators must comply with the requirements relied on in 40 CFR part 00 as in effect today. This

approach was agreed to and recommended to EPA

by SRP, UCT, and EDP in their August 22.1991

MOU and associated documents. At this time. EPA

believes that reliance on the regulations as they

currently exist Is reasonable in that they appear to

provide adequate technical methods and procedures

for determining and monitoring compliance with the

S02 emission linuitation established today.

significantly to visibility impairment in

the GCNP. Further, the technology

agreed to in the MOU will not increase

NO, or PM emissions from NGS.

Moreover, the docket does not contain

any evidence that NO. or PM emissions

from NGS would cause any such

impairments after compliance with the

final limitations promulgated today.

Thus, EPA finds no need to include

additional emission limitations for these

pollutants.

E. Source/Impairment Relationship

In the February 1991 proposal, EPA

estimated seasonal visual range changes

which were based on a simple rollback

model applied to average NGS

contribution during the entire WHITEX

study period. Based on thil modeL a 0.10

lb/MMBtu SOs emission limitation on

NGS should result in an approximate 14

percent improvement In seasonal

average standard visual range at Hopi

Point.

During the comment period on EPA's

February 1991 proposal, SRP submitted

the results and analyses of the NGSVS

which included estimates of NGS'

contribution to visibility impairments in

GCNP and specifically focused on Hopi

Point. The NGSVS data indicate that

controlling SO2 emissions from NGS

would result in at most a 2 percent

improvement in the seasonal average

standard visual range.

25

Another study 9a submitted during the

comment period, which was based on

modelling of NGS' emissions over a long

time period, indicated average

wintertime improvements in the range of

4 to 8 percent if NGS emissions are

reduced. This study is not based on any

specific monitoring period nor was it

based on an EPA-approved model.

The two intensive studies, WHITEX

and NGSVS, included detailed aerosol,

wind flow, and tracer analyses. They

represent snapshots of NGS' impacts for

their respective study periods. Based

solely on wind-flow analysis during

these periods, these studies varied

significantly in concluding how often

NGS emissions would be transported

directly to the Hopi Point, the common

GCNP monitoring site for both studies.

The major change in the seasonal

average visibility results from more

dramatic improvements expected to

occur as a result of reducing emissions

from NGS during certain meteorological

conditions. Recent measurements of

26 Average of the total light scattering to that part

apportioned to NGS over the entire study period as

found in appendix G of the NGSVS, Final Report,

Draft Number 2. Sonoma Technology, Inc.. April 16,

1991. s See Docket A-89-O2A. item IV-D-171.

peak winter sulfate levels in the canyon

approach four times the average winter

levels. For certain periods analyzed in

WHITEX and in NGSVS, NGS was

shown to be the dominant contributor

(more than 50 percent) to sulfates

measured at Hopi Point. If certain

humidity and wind conditions occur

during the period when very high sulfate

episodes are formed, reducing NGS

emissions could result in increases in

standard visual range up to 300 percent.

Given the variability in meteorological

conditions throughout the winter and

from one winter to the next, it is

impossible to exactly quantify the peak

episodic expected improvement for any

given period.

Photographic data taken during

WHITEX indicated that airflow'below

the rim of the canyon could result in

higher visibility impairment due to

trapping of pollution. As a result, a new

aerosol monitoring site atIndian

Gardens (4,000 feet below the rim of the

canyon) was established after the

WHITEX study. This site has provided

information since 1988 which confirms

that the transport and conversion

processes below the rim of the canyon

are sometimes decoupled from the

processes above the rim. Both NGSVS

and the NPS report on WHITEX used

the Hopi Point site, which is. above the

rim of the Canyon, as the basis for

determining the NGS impact on GCNP.

Data submitted during the comment

period show that visibility below the rim

is impaired more often and to a greater

degree than is the visibility above the

rim at Hopi Point. 27

Taking into account the conclusions

from both studies as well as other

monitoring information at GCNP'from

long-term monitoring, EPA expects that

reducing SO2 emissions from NGS to

0.10 lb/MMBtu should improve the

winter seasonal average visibility above

the rim of the canyon approximately 7

percent principally due to improvements

during episodes. Analyses of peak incanyon sulfate levels during winter

inversion episodes also lead EPA to

conclude that reductions in NGS SO2

emissions may well contribute to greater

episodic visibility improvement resulting

in, as discussed above, more than a 7

percent improvement in the seasonal

average visibility below the rim of the

canyon. However, EPA did not quantify

the expected visibility improvement

below the rim of the canyon due to the

limited amount of data and

understanding of the air transport

21 See Docket A-89-.2A, items IV-D-64, IV-D346, and IV---3.
Federal Register / Vol. 56, No. 192 / Thursday, October 3, 1991 / Rules and Regulations 50181

mechanisms below the rim of the

canyon.

F. Schedule of Compliance

As noted above, compliance with the

emission limitation will be phased-in by

unit on the following schedule:

1. One unit by November 19, 1997.

2. Two units by November 19, 1998.

3. All units by August 19, 1999.

The phasing in of the emission limitation

will allow NGS to initiate operation of

the control systems one at a time.

To ensure that NGS complies with the

emission limitation by the dates

specified. EPA has established a

schedule of compliance containing

interim deadlines as follow.

Date of binding contract for archi- June 1992.

tectural/Engineeodng firm to

design and procure the control

system needed for compliance.

Start of onsite construction of the Jan. 1995.

control system for the first unit.

Initiation of startup testing.

First unit ....................................... May 1997.

Seond.................... May 1998.

Third unit ........................ .... Feb. 1999.

the Administrator may extend the

interim deadlines if NGS can

demonstrate that compliance with the

final deadlines for compliance, stated

above, will not be affected.

G. Maintenance Schedule

The final regulation provides that by

March 16, 1993, and every March 16th

thereafter, the NGS owner or operator

will prepare a long-term maintenance

plan for NGS that maximizes winter

down-time while accommodating the

maintenance requirements for the other

generating facilities on the NGS grid.

The plan will cover the period from

March 16 to March 15 of the next year

and must provide at least a full 6 unitweeks of maintenance for NGS in the

November I to March 15 period, except

as provided below, to further reduce

SO2 emissions during the winter. The

plan will be developed as to be

consistent with the criteria established

by the Western States Coordinating

Council of the North American Electric

Reliability Council to ensure adequate

reserve margin. The full 6 unit-weeks of

winter maintenance need not occur if

any of the following circumstances

arise.

1. There is no need for 6 unit-weeks of

scheduled periodic maintenance in the

March 16-March 15 year covered by the

plan.

2. The reserve margin on any

electrical system served by NGS would

fall to an inadequate level, as defined by

the criteria referenced above. In such

case the scheduled maintenance may be

moved aut of the November 1 to March

15 period.

3. Th. cost of compliance with this

provision would be excessive. Costs of

compliance would be considered

excessive when the economic savings to

the participants of moving NGS'

maintenance out of the November I to

March 15 period exceeds $50,000 per

unit-day of maintenance moved.

4. A major forced outage at a unit

occurs ,)utside the winter months, and

necessary periodic maintenance occurs

during the period of forced outage.

The NGS owner or operator must

demonttrate to the satisfaction of the

Administrator that one or more of the

events listed above render unnecessary

or unreasonable a full 6 unit-weeks of

scheduled maintenance during the

specificd winter period. Where 6 unitweeks of scheduled maintenance is

unnecessary or unreasonable, the NGS

owner or operator must nevertheless

make best efforts to conduct as much

scheduled maintenance as practicable

during the winter period. If NGS does

not conduct its scheduled winter

maintenance (up to 6 unit-weeks), it

must report to EPA why it did not do so.

When maintenance is being

conducted on a unit, the unit will not be

in operation and therefore not emitting

SO2 . Thus, the shifting of NGS

maintenance to the wintertime period

will further reduce NGS SO2 emissions

during the period when NGS is

suspected to have its greatest impact on

the GCNP. Further, because the

scheduled winter maintenance

requirement will be implemented in the

winter of 1993-1994, it will have the

effect ef making a degree of reasonable

progress toward the national visibility

goal before final compliance with the

emission limitation is required. Because

NGS must, for normal operation,

conduct this maintenance, rescheduling

it in tht) wintertime period should have

little economic impact on NGS.

H. Air Quality Review

The installation and operation of a

wet FGD control system at NGS (the

proven available technology that EPA

anticipates will be used) will lower the

exhaust gas temperature from the stacks

and could reduce the plume rise above

the NGS stacks. The EPA and the

Arizona Department of Environmental

Quality reviewed the need to reheat the

exhaust gases to ensure appropriate

plume A ise with the lower gas exit

temperatures associated with meeting a

0.10 lb/MMBtu emission limitation using

wet FGD and found that reheating of the

exhaust gas will not be necessary to

prevent a violation of any national

ambient air quality standards. If the

exhaust gas Is not reheated, the control

cost will be reduced significantly.

If NGS were to select a wet FGD SO2

control system, the water content of the

plume would increase. Under certain

conditions, a white steam plume will

occur as the water vapors condenses

before it dissipates. This steam plume

may be visible near the stack. However,

it will not cause any visibility

impairment in GCNP or surrounding

mandatory Class I Federal areas and

will not interfere with the attainment of

any national ambient air quality

standards. Such steam plumes are not

subject to any State or Federal visual

emission standards or regulations.

III. Response to Comments

The September 5, 1989, February 8,

1991, and August 13, 1991 notices

requested comment on a variety of

issues relating to attribution of

impairment, cost of controls, and the

benefit expected from the controls. In

addition, EPA held a public hearing on

March 18 and 19, 1991 during which EPA

received comments on its February 1991

proposal.

Under section 307(d) of the Act,

today's action must be accompanied by

a response to each of the significant

comments, criticisms, and new data

submitted in written or oral

presentations during the comment

period. The EPA has carried out this

duty. Moreover, modifications to the

proposed rule have been made in

response to public comments. The EPA's

final control strategy for NGS largely

embodies public comments received

from representatives of GCT, EDF, and

SRP which, in turn, were subject to

public comment (see, e.g., 56 FR 38399

(August 13, 1991)). Further, in its

February 1991 proposal, EPA requested

comment on several control options

including, but not limited to, the

following rule elements and specific

regulatory alternatives:

1. Emission limitations, including

limitations ranging between 0.50 and

0.10 lb/MMBtu.

2. Averaging times, including a 3-hour.

30-day, and annual averaging period.

3. Implementation schedules,

including one providing for plant-wide

compliance by the year 2000. As noted

below, EPA received many comments in

response to the February 1991 proposal

supporting, in part, the control elements

adopted by EPA, in total, today. For

example, many citizens and

representatives of environmental

organizations submitted comments

supporting a 0.10 lb/MMBtu emission

limitation, the emission limitation

adopted today. Many representatives of
50182 Federal Register / Vol. 56, No. 192 / Thursday, October 3, 1991 / Rules and Regulations

industry and business submitted

comments supporting an annual

averaging period and a long compliance

schedule.

During the initial public comment

period, EPA received over 400 comments

including the public hearing transcript.

A summary of the significant comments,

criticisms, and new data submitted in

written or verbal presentations during

the public comment period and EPA's

responses are provided below and in

supporting documents which have been

placed in Docket A-89-02A. 28 , 29

During the supplemental comment

period, EPA received 21 additional

comments. Two commenters objected to

requiring any additional pollution

controls on NGS because of the

uncertainty in the impairment

attribution. Eighteen commenters

generally supported the adoption of a

control strategy consistent with the

MOU, although one commenter

expresssed some concerns about the

compliance schedule and exemption

from winter maintenance. One

commenter objected because of the

delayed compliance and the level of

control.

The SRP, GCT, EDF, the Wilderness

Society, the National Wildlife

Federation, and the Sierra Club have

conditionally withdrawn prior

comments that are inconsistent with the

August MOU entered by representatives

of SRP, GCT, and EDF and associated

recommendations to the Agency. In light

of this withdrawal, some of the

comments discussed here and in the

supplementary response to comments

documents placed in the rulemaking

docket are no longer pending before the

Agency and, clearly, no longer "significant" within the meaning of

section 307(d) of the Act. Nevertheless,

EPA has discussed them in order to help

the public better understand today's

action.

A. Attribution

The EPA received a large number of

comments on its attribution of visibility

impairment in the GCNP to NGS. These

comments expressed a variety of

opinions including statements that EPA

har already made an attribution

decision and that EPA should not revisit

that decision, that more than adequate

infcjimation was available to make such

a decision and that it is clear from the

record that certain visibility impairment

28 JCM Environmental "Summary of Public

Comments, Proposed Revision to Arizona Visibility

FIP'for Navajo Generating Station" July 1991.

29 See U.S. EPA. "Response to Public Comments,

Proposed Revisions to Arizona Visibility FIP."

September 1991.

episodes in GCNP are attributable to

NGS, that EPA should not make a

decision to attribute the impairment to

NGS until it developed a strong sourceimpairment relationship, and that EPA

should not attribute the impairment to

NGS since it is not the sole cause of the

impairment in the GCNP. In its February

1991 proposal, EPA reopened its

comment period on and exolicitlv

requested public comment on its

preliminary attribution decision.

Therefore, EPA's proposed attribution

decision was subject to public comment.

As explained earlier, EPA has reviewed

the available technical data and

analyses and has concluded that

episodic visibility impairment in GCNP

is reasonably attributable to NGS.

B. Source-Impairment Relationship

Once EPA attributed impairment to

NGS, it then had to develop a sourceimpairment relationship in order to

estimate the expected improvements in

visibility resulting from the installation

of the controls.

In the February 1991 proposal, EPA

provided calculations of the relationship

between reductions in SO2 emissions

from NGS and the visibility at the

GCNP. The calculations were based on

the overall findings of the WHITEX

report which used several techniques to

apportion NGS' contribution to sulfates

and the resulting haze at GCNP. The

EPA calculated two measures of

visibility improvements, one seasonal

average change in standard visual range

and the other a distribution of days

where control of NGS would result in

several levels of contrast changes. The

EPA received several comments that its

calculations used to estimate the

distribution of days when the reduction

in SO2 emissions from NGS would result

in perceptible, quite noticeable, and

very apparent change in contrast in

GCNP were in error because the final

contrast assessment did not take into

account natural (Rayleigh) atmospheric

scattering of light. The EPA agrees that

these calculations did not take into

account Rayleigh scattering. However,

EPA's seasonal visual range estimated

in the February 1991 proposal, did not

include error as some commenters had

alleged and is relied on in today's

action.

The EPA has received new

information during the comment period

which has improved its understanding of

the source-impairment relationship.

Based on this and other available

information, EPA has refined the sourceimpairment relationship and concluded

that it is as described in the SourceImpairment discussion in "Today's

Action" above.

C. Emission Limitation

Individuals and groups that

commented on the emission limitation

generally requested that EPA adopt a

requirement for the maximum level of

control or no controls at all. No

commenters supported the 50 percent

control level. Some commenters

supported an SRP proposal, now

withdrawn, which called for a 70

percent level. Most commenters on the

emission limitation supported a 90 or 95

percent control level. The commenters

that did not support controls did so

because of the cost of the controls and/

or the alleged lack of a strong

demonstrated source-impairment

relationship. As discussed, EPA believes

that an adequate source-impairment

relationship does exist for EPA to

require NGS to-control its emissions.

The control strategy that EPA is

promulgating today will provide a 90

percent reduction in the SO2 emissions

from NGS at a cost below that which

would have been necessary to meet the

control strategy EPA proposed in

February 1991. Thus, the control strategy

adopted by EPA satisfies both groups of

commenters in that it will result in a

greater emission reduction at a lower

cost. Further, as noted previously, EPA

must balance a number of factors in

taking action today under section 169A.

Such action must be balanced in light of

EPA's statutory mandate set out in

section 169A to make "reasonable

progress" toward the national goal of

"the'prevention of any future, and the

remedying of any existing, impairment

of visibility in mandatory class I Federal

areas which impairment results from

man-made air pollution." The EPA

carefully has weighed. for example, the

estimated cost of compliance with

today's emission limitation and the

visibility benefits expected to be

realized and concluded that today's

control strategy, taken together, is a

reasonable exercise of its delegated

rulemaking authority under section

169A.

D. Averaging Time

Several commenters supported a short

(3-hour) averaging time stating that it

would ensure that maximum visibility

protection. Some of these comments

have been withdrawn. Other

commenters supported a longer (30 days

to annual) averaging time stating that it

would eliminate the need for expensive

backup control equipment. The EPA's

adoption of the control strategy, which

includes an annual rolling average

emission limitation, will eliminate the

need for the backup equipment.
Federal Register / Vol. 56, No. 192 / Thursday, October 3, 1991 / Rules and Regulations 50183

However, the control strategy also

includes a stringent emission limitation

and winter maintenance scheduling to

ensure maximum visibility protection.

E. Compliance Schedule

Several commenters noted that

section 169A of the Act requires that

BART emission limitations be met

within 5 years. Some of the commenters

have since withdrawn these comments.

Others commented that it was legally

permissible for compliance with a BART

emission limitation to extend beyond 5

years. In EPA's August 1991 notice

reopening the comment period, EPA

published a memorandum from its

Office of General Counsel that

described the legal basis for the 1997,

1998, and 1999 compliance schedule

adopted today. No adverse comments

addressing the legal basis were received

during the supplemental comment

period. Therefore, as discussed in the

August 1991 notice, EPA is relying

principally on the reasonable progress

requirements of section 169A(b)(2). The

requirements of that section, which

encompasses both the long-term

strategy and BART provisions, are met

by today's action.

F. BART Guidelines

In the February 1991 proposal (56 FR

5178 col. 1), EPA requested comments on two potential revisions to the BART

Guidelines. First, EPA requested

comment on the continued use of the

new source performance standards as a

base for the BART analysis. Second,

EPA requested comment on whether it

should include the consideration of the

value of marketable allowances when

estimating the cost of control systems.

The EPA received several comments on

both issues. However, in making its final

determination on today's action, neither

of these issues were significant.

Therefore, EPA is not making a final

decision on whether to revise the BART

Guidelines at this time.

G. Cost of Controls

Several commenters alleged that EPA

may have overestimated the economic

impact of the controls. They also noted

that costs are quite small when divided

up among the various consumers. Other

commenters alleged that the increased

cost will have a significant Impact on

the consumers. The EPA has

recalculated the cost of the controls of

today's final action based upon the new information provided by SRP. Those

numbers may be overestimates of the

actual cost of control. Even if the actual

control costs are consistent with SRP

and EPA estimates, as noted. EPA has

concluded that today's. action achieves

greater visibility benefit at less cost than

EPA's February 1991 proposed option.

Moreover, by balancing the estimated

costs, expected visibility improvement

and other relevant factors EPA has

concluded that the expected

Improvements in the visibility In the

GCNP justify the estimated costs.

Several commenters noted that the

recipients of CAP water face a greater

price increase than electricity customers

or will otherwise bear a significant

economic hardship as a result of the

control costs of today's action. As

discussed in the Regulatory Flexibility

Act (RFA) section below, EPA cannot

estimate every potential indirect cost of

today's action. Nevertheless, EPA has

carefully considered the potential

impacts of today's action on recipients

of CAP water, including farmers

receiving such water. The Central

Arizona Water Conservation District

(CAWUD) submitted an estimate of a 7

percent to 10 percent increase in

agricultural water rates, resulting in an

increased water cost of nearly $10,000

per year for a typical family farmer. The

EPA estimates such an increase would

be less than a 2 percent increase in the

total variable costs of a typical farm. At

the present time, agricultural water in

Arizona receives a substantial Federal

subsidy. Current Federal policy calls for

phasing out the water subsidy. When

the subsidy is eliminated, the Impact of

the increased cost at NGS will be an

even smaller percentage of both total

variable cost and total water cost. The

EPA has weighed and balanced the

costs of today's action, the expected

visibility improvement, and other

requisite considerations and concluded

that today's control strategy, taken

together, constitutes a reasonable

exercise of EPA's delegated rulemaking

authority under section 169A of the Act.

H. Impaicts on Other Class I Areas

Several commenters noted the impact

of NGS on the other class I areas In the

region known as the "Golden Circle."

Two of the commenters provided

photographs and modeling to support

their statements. The EPA agrees that

NGS could contribute to the visibility impairment in those other areas, but the

data and modeling that were presented

were not adequate for EPA to use in

making a definitive determination on

attribution of the impairment in those

areas to NGS. However, the controls

that are being required today will

significantly reduce if not eliminate

NGS' contribution to the visibility

impairment in those areas.

I Reasonal Controls

In the February 1991 proposal. EPA

requested comment on whether, as a

policy matter, it should allow seasonal

controls at NGS and whether, if

technically justified, seasonal controls

would be legally permissible. Several

commenters recommended that EPA

adopt a control strategy for NGS that

include seasonal controls and/or

commented that seasonal controls could

lawfully constitute an emission

limitation representing BART under

section 109A. Several others commented

that the technical record did not support

seasonal controls and/or commented

that as a legal matter seasonal controls

could not constitute an emission

limitation under section 169A. During

the comment period, the GCT and Its

consultants presented analyses, which

are in the rulemaking docket.

demonstrating that NGS' emissions may

significantly impair visibility year-round

at the GCNP as well as other Class I

areas in the region. For example, a

simple transport and transformation

model of NGS emissions over a 5-year

period indicated impacts at GCNP in

seasons other than winter. While the

degree of visibility impairment during

these impacts Is less than those

documented by other studies during the

winter period, the impacts arn

nevertheless strongly suggestive of

attributable impairment in non-winter

seasons. Further, the analyses suggest

that NGS emissions could impair

visibility in surrounding Class I areas

between 60 and 80 percent of the time

year-round. For the foregoing reasons,

EPA concludes that year-round controls

are appropriate in this action. The EPA's

decision also Is consistent with the

recommendations of the parties. While

EPA's regulations do not cover regional

haze effects from existing sources, EPA

also notes that today's action will lead

to regional haze benefits as well.

Therefore, EPA need not determine

whether such controls would be legally

permissible.

j. Monetary Benefits

In the February 1991 proposal. EPA

noted that it was not legally required to

estimate the monetary benefits

associated with improving visibility in

the GCNP. However, as a check of the

reasonableness of its approach, EPA

evaluated and considered the benefit

analysis developed as a part of the draft

RIA for the proposed rule. The EPA

requested comment on its monetary

benefits analysis and a monetary

benefits analysis conducted by SRP.

Some commenters stated that EPA and
50184 Federal Register / Vol. 56, No. 192 / Thursday, October 3, 1991 / Rules and Regulations

SRP had underestimated the monetary

benefits while others indicated that

EPA's benefits were overstated. Because

the benefits analysis forms no part of

legal basis for today's action, EPA is not

responding to those comments.

IV. EDF v. Reilly

Today's action regarding NGS

completes EPA's obligations under the

settlement agreement in EDF v. Reilly,

No. C82-6850 (N.D. Cal.), and under the

first round of SIP/FIP planning called for

in the visibility regulations.

V. Nonprecedential Effect of This Action

Today's promulgation is limited to the

rulemaking requiring an SO2 emission

limitation for NGS in order to remedy a

single-source visibility impairment in the

GCNP that is traceable to NGS and,

hence, remediable under EPA's 1980

visibility regulations. As such, it has no

direct precedential effect on any other

rulemaking action EPA might undertake

in the future regarding other existing

sources or Class I areas. This is so

because the outcome of this rulemaking

has been highly dependent upon facts

and circumstances that are unique to

this proceeding and thus does not apply

to other cases. For example, the tracer

studies and other analyses contained in

the WHITEX and NGSVS reports that

are key to a showing that impairment at

GCNP is traceable to NGS are not being

approved for use in any other

rulemaking addressing other potential

sources of visibility impairment. Should

EPA or State agencies conduct visibility

rulemakings regarding other Class I

areas and other existing sources of

pollution in the future, they will need to

rely on attribution techniques

appropriate for those other areas and

sources in order to make reasoned

regulatory decisions. They will not be

able to rely solely on WHITEX or

NGSVS findings that specifically

address the GCNP and NGS to

determine the existence of impairment

that is reasonably attributable to any

such other source. Likewise, neither the

methodology used for establishing the

expected improvement in visibility that

could be anticipated to result from use

of alternative S0 2 control-systems nor

the final emission limit being

promulgated today will have direct

precedential effect elsewhere. The

statutory requirement that EPA weigh

various factors before reaching a

decision is by nature a case-specific

process.

A. Classification

Executive Order No. 12291 requires

each Federal agency to determine if a

regulation is a "major" rule as defined

by the order and "to the extent

permitted by law,".to prepare and

consider an RIA in connection with

every major: rule. Major rules are

defined as those likely to result in:

1. An annual effect on the economy of

$100 million or more.

2. A major increase in costs or prices

for consumers or individual industries;

Federal, State, or local government

agencies; or geographic region.

3. Significant adverse effects on

competition, employment, investment,

productivity, innovation, or the ability of

the United States-based enterprises to

compete with foreign-based enterprises

in domestic or export markets.

The EPA judged the February 1991

proposed regulation for NGS to be a

major rule based on projected

annualized costs potentially in excess of

$100 million. The EPA then prepared a

preliminary RIA that included estimates

of costs, benefits, and net benefits for

three control options. The preliminary

analysis, titled "Regulatory Impact

Analysis of a Revision of the Federal

Implementation Plan for the State of

Arizona to Include SO2 Controls for the

Navajo Generating Station," and an

addendum, titled "Addendum to the

Regulatory Impact Analysis of a

Revision of the Federal Implementation

Plan for the State of Arizona to Include

SO2 Controls for the Navajo Generating Station" are available in Docket A-89-

02A.

In light of the reduced estimated cost

of this rule, the Office of Management and Budget (OMB] has exempted this

action from the RIA requirements.

Therefore, EPA did not finalize the

preliminary RIA.

B. Paperwork Reduction Act

This rule will impose a modest

reporting burden on the participants of

the NGS to enable EPA to ensure

compliance with the emission limits.

Because the reporting burden affects

only a single source, it is not subject to

OMB review under the Paperwork

Reduction Act.

C. Section 317(c) Economic Impact

Assessment

This action is taken pursuant to

sections 169A and 110(c) of the Act, and

a section 317(c) economic impact

assessment may not be required.

However, all of the analytical

requirements of section 317(c) have been

met. The section 317(c)(1) analysis of

alternative regulations, and the impact of varying the effective date, are

essential considerations in promulgating

this revision to the FIP for Arizona. Each

of the section 317(c) requirements are

included in the BART analysis prepared

by EPA. Portions of the economic impact

assessment are revisedin this notice

based on additional information and

comments provided to EPA..

D. Regulatory Flexibility Act

Under the RFA, 5 U.S.C. 601-612, EPA

must prepare for rules subject to notice

and comment rulemaking initial and

final regulatory flexibility analyses

describing the impact on small entities

which includes small businesses, small

not-for-profit enterprises, and

governmentpl entities with jurisdiction

over populations of less than 50,000. The

requirement of preparing such is

inapplicable, however, if the

Administrator certifies that the rule will

not have a significant economic impact

on a substantial number of small entities

(see 5 U.S.C. 605(b)).

In the February 1991 proposal, the

Administrator certified that the

proposed rule would not have a

significant impact on a substantial

number of small entities because none

of the participants of NGS are classified

as small according to the guidelines

developed by the Small Business

Administration. Moreover, EPA

estimated that for all of the electric

utilities using NGS power, the impact on

electric utility rates would be'

substantially less than 5 percent.

Similarly, the emission limitation

being established today does not have a

direct impact on and will not apply to a

substantial number of small entities

because none of the participants of NGS

subject to today's action are classified

as small according to the guidelines

developed by the Small Business

Administration. Further, during the

comment period on the February 1991

proposal and the August 1991

supplemental notice, SRP, NPC, and

CAWCD submitted comments indicating

that the potential indirect costs that may

be passed on to customers of the NGS

participants were less than those

estimated by EPA.

The comments on potential indirect

costs incurred by rate payers submitted

by SRP, NPC, CAWCD, and others do

not address the costs incurred directly

by the NGS participants, the entities

that are subject to and directly impacted

by today's action and that do not qualify

as "small." Further, except for the

general comments submitted by the

Bureau of Reclamation, the comments

do not address EPA's conclusion under

the RFA that the proposed rule would

not have a significant economic impact.

on a substantial number of small

entities. Before discussing the

comments, EPA notes that it cannot and

is not legally required to foresee all of
Federal Register / Vol. 56, No. 192 / Thursday, October 3, 1991 / Rules and Regulations 501.85

the indirect impacts associated with

today's action. The EPA cannot

anticipate how the NGS participants

will seek to pay for the costs associated

with today's action, the decisions that

public utility commissions will confront

and make, etc. Nevertheless, EPA has

considered and attempted to respond to

those comments addressing indirect

costs impacting potential small entities

in order to explain more fully for the

public the Administrator's finding under

the RFA that today's final rule will not

have a significant impact on a

substantial number of small entities.

In the draft RIA, EPA estimated a $92

million per year control cost would

increase SRP's and NPC's electric rates

by a maximum of 3.1 percent and 4.4

percent, respectively.30 The EPA

estimated that of the six utilities

receiving power from NGS, these two

would experience the greatest electric

rate increases if power generation costs

were passed through completely to

consumers because both SRP and NPC

rely on 25 percent of NGS electricity for

their total sales and each has a low

average cost/kWh relative to the other

four participants. Further, EPA

estimated that these percentage

estimates likely were overestimates due

to various dampening effects omitted

from the calculation.

The NPC submitted comments on

EPA's February 1991 proposal in which

it estimated that the control costs would

result in a 2.27 percent increase for its

residential customers. The SRP also

submitted comments on the February

1991 proposal in which it estimated that

a control strategy costing $90 million

would result in a 2.1 percent to 2.5

percent increase to its rate payers.

These estimated increases are less than

the 5 percent impact estimated in EPA's

February 1991 proposal. Further, these

costs may be overestimated in that, for

example, today's control option is

cheaper than that advanced in the

February 1991 proposal. In addition, the

sale of SO2 allowances under the SO2

allowance trading program established

by EPA under title IV of the Act may

mitigate costs.

In the draft RIA for the February 1991

proposal, EPA also estimated the

economic impact on CAP water users.

The EPA estimated an 18 percent

increase in water costs for farmers

receiving agricultural water from the

CAP. This estimate translated into a

$11/acre-foot increase (3 cents per 1000

gallons of water) raising the total annual

variable costs for a 800-900 acre farm

3o See generally "Draft Regulatory Impact

Analysis of a Revision of the Federal

Implementation Plan for the State of Arizona to

Include SO2 Controls for the Navajo Generating

Station."

(the size of the average farm served by

CAP) by 3-4 percent per year ($22,000/

year). The EPA further explained why

these costs were anticipated to be

overestimates and how the costs

compar:-d with unsubsidized non-CAP

water.

At the public hearing on the February

1991 proposal, a member of the Board of

Directors of the CAWCD testified that

their analysis concluded the NGS

control costs would result in a $4.50 per

acre-foot increase in CAP water, less

than EPA's $11 estimate. The CAWCD

further testified that the $4.50/acre-foot

would translate into an annual cost

increase of $7,200 for the average farmer

irrigating 800 acres. In comments dated

September 6, 1991 addressing the

proposal identified in EPA's August 1991

suppleiaental notice, CAWCD generally

commented that the control costs will

add 7 to 10 percent to the annual costs

of its water delivery and, in turn,

additional costs of nearly $10,000 per

year for CAP water for a typical farmer,

costs of approximately $3 million

annually on all of its municipal water

suppliers taken together, and a $1.5

million annual increase on Indian tribes.

As evident, the CAWCD cost figures

are inconsistent in that testimony at the

public hearing and the written text

accompanying that testimony estimated

an annual Impact of $7,200 on the

average farmer, plus comments dated

September 6, 1991 estimated that costs

would be "nearly $10,000 per year." The

inconsistency Is further perplexing in

that the option advanced in the August

1991 notice was less expensive than that

identified in the February 1991 proposal.

Because CAWCD's comments on costs

are general and undocumented, EPA

cannot check their derivation. In any

case, both cost figures are less than half

of that identified in EPA's draft RIA. The

EPA estimates that the $7,200 and

$10,000 cost figures submitted by

CAWCD would translate into a 1

percent to 2 percent increase in total

variable costs for the average farmer.

The EPA has no reason to believe that

the percentage increase in costs of

water for municipal suppliers or Indian

tribes will be substantially different

from the economic impact on farmers

purchasing CAP water. Further, as noted

above, the owner of NGS may

substantially mitigate the costs of

today's action by selling SO

allowances. This, in turn, should curb

any indirect costs incurred.

Finally, in commenting on EPA's

February 1991 proposal, the Bureau of

Reclamation (the Bureau) generally,

commented on EPA's conclusion that an

initial RFA was unnecessary by noting

that testimony at the public hearing

provided evidence of adverse impacts

on small businesses, farmers,

governmental entities, and Indian tribes.

In its only example of cost impacts, the

Bureau commented that the agricultural

customers of the CAWCD could

experience increases in their water rates

of approximately $10 per acre-foot

which, they commented, would result in

a 16 percent increase in annual costs for

CAWCD's large customers.

The Bureau's comments that

agricultural customers of CAWCD could

experience increases in water rates of

approximately $10 per acre-foot are

inconsistent with CAWCD's own

comments which suggested an impact of

approximately $4.50 per acre-foot and,

further, were not substantiated. In

addition, the Bureau's $10 per acre-foot

estimate is lower than EPA's more

conservative estimate. The Bureau's

comments also were based on the

February 1991 option which, as noted, is

more costly than today's final action.

Based on the CAWCD comments, EPA

estimates that today's action will result

in less than a 2 percent increase in the

total variable costs for the average

CAWCD farmer.

As noted, EPA has estimated the cost

impacts on the residential customers of

SRP and NPC. Residential customers are

usually the category of consumers

bearing the greatest impact in cost

increases because most utility rate

structures typically charge

incrementally less for the more power

that is consumed. Further, as noted, EPA

expects the impacts on the residential

customers of NPC to be higher than any

other customers of the NGS participants.

Thus, EPA's estimate of the impact on

NPC residential customers serves as a

worst-case check on the potential

electricity rate impacts on other

potential customers. The impact on all

potential small entities, including school

districts, local governments, business

establishments, not-for-profit

enterprises, etc., should be similar or

smaller. Thus, not only were the

Bureau's general claims about potential

impacts on small entities undocumented,

but EPA believes its consideration of the

impacts on residential rate payers

affords a reasonable check of the

potential impacts on other NGS

electricity customers.

Accordingly, for all of the reasons

stated, I hereby certify that the

regulation being promulgated today will

not have a significant economic impact

on a substantial number of small

entities.
50186 Federal Register / Vol. 56, No. 192 / Thursday, October 3, 1991 / Rules and Regulations

'i. Interagency Review 5 :

This final rule was submitted to OMB

for review. Drafts submitted to OMB for

review, written comments on these

drafts by OMB or other agencies, and

FPA's written responses to such

comments have been placed in the

rulemaking docket.

List of Subjects in 40 CFR Part 52

Air pollution control, Nitrogen

dioxide, Particulate matter, Carbon

monoxide, Ozone, Lead, Sulfur oxides,

Reporting and recordkeeping

requirements.

Dated: September 18, 1991.

William K. Reilly,

Administrator.

PART 52--AMENDED]

1. The authority for part 52 continues

to read as follows:

Authority: 42 U.S.C. 7401-7642.

2. Section 52.145 is amended by

adding paragraph (d) to read as follows:

§ 52.145 Visibility protection. * * * * *

(d) This paragraph is applicable to the

fossil fuel-fired, steam-generating

equipment.designated as Units 1, 2, and

3 at the Navajo Generating Station in

the Northern Arizona Intrastate Air

Quality Control Region (§ 81.270 of this

chapter).

(1) Definitions.

Affected Unit(s) means the steamgenerating unit(s) at the Navajo

Generating Station, all of which are

subject to the emission limitation in

paragraph (d)(2) of this section, that has

accumulated at least 365 boiler

operating days since the passage of the

date defined in paragraph (d)(6) of this

section applicable to it.

Administrator means the

Administrator of EPA or his/her

designee.

Boiler Operating Day for each of the

boiler units at the Navajo Generating

Station is defined as a 24-hour calendar

day (the period of time between 12:01

a.m. and 12:00 midnight in Page,

Arizona) during which coal is

combusted in that unit for the entire 24

hours.

Owner or Operator means the owner.

participant in, or operator of the Navajo

Generating Station to which this

paragraph is applicable.

Unit-Week of Maintenance means a

per'od of 7 days during which a fossil

fuel-fired steam-generating unit is under

repair, and no coal is combusted in the

unit.

(2) Emission limitation. No owner or

operator shall discharge or cause the

discharge of sulfur oxides into the

atmosphere in excess of 42 ng/J [0.10

pound per million British thermal units

(lb/MMBtu)] heat input.

(3) Compliance determination. Until at

least one unit qualifies as an affected

unit, no compliance determination is

appropriate. As each unit qualifies for

treatment as an affected unit, it shall be

included in the compliance

determination. Compliance with this

emission limit shall be determined daily

on a plant-wide rolling annual basis as

follows:

(i) For each boiler operating day at

each steam generating unit subject to

the emission limitation in paragraph

(d)(2) of this section, the owner or

operator shall record the unit's hourly

SO2 emissions using the data from the

continuous emission monitoring

systems, [required in paragraph (d)(4) of

this section] and the daily electric

energy generated by the unit (in

megawatt-hours) as measured by the

megawatt-hour meter for the unit.

(ii) Compute the average daily S02

emission rate in ng/J (lb/MMBtu)

following the procedures set out in

method 19, appendix A, 40 CFR part 60

in effect on October 3, 1991.

(iii) For each boiler operating day for

each affected unit, calculate the product

of the daily S0 2 emission rate

(computed according to paragraph

(d)(3)(ii) of this section) and the daily

electric energy generated (recorded

according to paragraph (d)(3)(i) of this

section) for each unit.

(iv) For each affected unit, identify the

previous 365 boiler operating days to be

used in the compliance determination.

Except as provided in paragraphs (d)(9)

and (d)(10) of this section, all of the

immediately preceding 365 boiler

operating days will be used for

compliance determinations.

(v) Sum, for all affected units, the

products of the daily SO2 emission rateelectric energy generated (as calculated

according to paragraph (d)(3)(ii) of this

section) for the boiler operating days

identified in paragraph (d)(3)(iii) of this

section.

(vi) Sum, for all affected units, the

daily electric energy generated

(recorded according to paragraph

(d)(3)(i) of this section) for the boiler

operating days identified in paragraph

(d)(3)(iii) of this section.

(vii) Calculate the weighted plantwide annual average S02 emission rate

by dividing the sum of the products

determined according to iv above by the

sum of the electric energy generated

determined according to paragraph

(d)(3)(v) of this section.

(viii) The weighted plant-wide annual

average SO2 emission rate shall be used

to determine compliance with the

emission limitation in paragraph (d)(2)

of this section.

(4) Continuous emission monitoring.

The owner or operator shall install,

maintain, and operate continuous

emission monitoring systems to

determine compliance with the emission

limitation in paragraph (d)(2) of this

section as calculated in paragraph (d)(3)

of this section. This equipment shall

meet the specifications in appendix B of

40 CFR part 60 in effect on October 3,

1991. The owner or operator shall

comply with the quality assurance

procedures for continuous emission

monitoring systems found in appendix F

of 40 CFR part 60 in effect on October 3,

1991.

(5] Reporting requirements. For each

steam generating unit subject to the

emission limitation in paragraph (d)(2)

of this section, the owner or operator:

(i) Shall furnish the Administrator

written notification of the SO, oxygen,

and carbon dioxide emissions according

to the procedures found in 40 CFR § 60.7

in effect on October 3, 1991.

(ii) Shall furnish the Administrator

written notification of the daily electric

energy generated in megawatt-hours.

(iii) Shall maintain records according

to the procedures in 40 CFR 60.7 in effect

on October 3, 1991.

(iv) Shall notify the Administrator by

telephone or in writing within one

business day of any outage of the

control system needed for compliance

with the emission limitation in

paragraph (d)(2) of this section and shall

submit a follow-up written report within

30 days of the repairs stating how the

repairs were accomplished and

justifying the amount of time taken for

the repairs.

(6) Compliance dates. The

requirements of this paragraph shall be

applicable to one unit at the Navajo

Generating Station beginning November

19, 1997, to two units beginning

November 19, 1998, and to all units

beginning on August 19, 1999.

(7) Schedule of compliance. The

owner or operator shall take the

following actions by the dates specified:

(i) By June 1, 1992, award binding

contracts to an architectural and

engineering firm to design and procure

the control system needed for

compliance with the emission limitation

in paragraph (d)(2) of this section.

(ii) By January 1, 1995, initiate on-site

construction or installation of a control

system for the first unit.

(iii) By May 1, 1997, initiate start-up

testing of the control system for the first

unit.
Federal Register / Vol. 56, No. 192 / Thursday, October 3, 1991 / Rules and Regulations 50187

(iv) By May 1, 1998, initiate start-up

testing of the control system for the

second unit.

(v) By February 1, 1999, initiate startup testing of the control system for the

third unit.

The interim deadlines will be extended

if the owner or operators can

demonstrate to the Administrator that

compliance with the deadlines in

paragraph (d)(6) of this section will not

be affected.

(8) Reporting on compliance schedule.

Within 30 days after the specified date

for each deadline in the schedule of

compliance (paragraph (d)(7) of this

section, the owner or operator shall

notify the Administrator in writing

whether the deadline was met. If it was

not met the notice shall include an

explanation why it was not met and the

steps which shall be taken to ensure future deadlines will be met.

(9) Exclusion for equipment failure

during initial operation. For each unit, in

determining compliance for the first year

that such unit is required to meet the

emission limitation in paragraph (d)(2)

of this section, periods during which one

of the following conditions are met shall

be excluded:

(i) Equipment or systems do not meet

designer's or manufacturer's

performance expectations.

(ii) Field installation including

engineering or construction precludes

equipment or systems from performing

as designed.

The periods to be excluded shall be

determined by the Administrator based

on the periodic reports of compliance

with the emission limitation in

paragraph (d)(2) of this section which

shall identify the times proposed for

exclusion and provide the reasons for

the exclusion, including the reasons for

the control system outage. The report

also shall describe the actions taken to

avoid the outage, to minimize its

duration, and to reduce SO 2 emissions at

the plant to the extent practicable while

the control system was not fully

operational. Whenever the time to be

excluded exceeds a cumulative total of

30 days for any control system for any

affected unit, the owner or operators

shall submit a report within 15 days

addressing the history of and prognosis

for the performance of the control

system.

(10) Fxclusion for catastrophic failure.

In addition to the exclusion of periods

allowed in paragraph (d)(9) of this

section, any periods of emissions from

an affected unit for which the

Administrator finds that the control

equipment or system for such unit is out

of service because of catastrophic

failure of the control system which

occurred for reasons beyond the control

of the owner or operators and could not

have been prevented by good

engineering practices will be excluded

from the compliance determination.

Events which are the consequence of

lack of appropriate maintenance or of

intentional or negligent conduct or

omissions of the owner or operators or

the control system design, construction,

or operating contractors do not

constit'nte catastrophic failure.

(11) Equipment operation. The owner or operator shall optimally operate all

equipment or systems needed to comply

with the requirements of this paragraph

consistent with good engineering

practic3s to keep emissions at or below

the emission limitation in paragraph

(d)(2) of this section, and following

outage; of any control equipment or

systems the control equipment or system

will be returned to full operation as

expeditiously as practicable.

(12) Maintenance scheduling. On

March 16 of each year starting in 1993,

the owner or operator shall prepare and

submit to the Administrator a long-term

maintenance plan for the Navajo

Generating Station which

accommodates the maintenance

requirements for the other generating

facilities on the Navajo Generating

Station grid covering the period from

March 16 to March 15 of the next year

and showing at least 6 unit-weeks of

maintenance for the Navajo Generating

Station during the November 1 to March

15 period, except as provided in

paragraph (d)(13) of this section. This

plan shall be developed consistent with

the criteria established by the Western

States Coordinating Council of the North

American Electric Reliability Council to

ensure an adequate reserve margin of

electric generating capacity. At the time

that a plan is transmitted to the

Administrator, the owner or operator

shall notify the Administrator in writing

if less than the full scheduled unit-weeks

of maintenance were conducted for the

period covered by the previous plan and

shall furnish a written report stating

how that year qualified for one of the

exceptions identified in paragraph

(d)(13) of this section.

(13) Exceptions for maintenance

scheduling. The owner or operator shall

conduct a full 6 unit-weeks of

maintenance in accordance with the

plan required in paragraph (d)(12) of this

section unless the owner or operator can

demonstrate to the satisfaction of the

Administrator that a full 6 unit-weeks of

maintenance during the November 1 to

March 15 period should not be required

because of the following:

(i) There is no need for 6 unit-weeks of

scheduled periodic maintenance in the

year covered by the plan;

(ii) The reserve margin on any

electrical system served by the Navajo

Generating Station would fall to an

inadequate level, as defined by the

criteria referred to in paragraph (d)(12)

of this section.

(iii) The cost of compliance with this

requirement would be excessive. The

cost of compliance would be excessive

when the economic savings to the owner

or operator of moving maintenance out

of the November 1 to March 15 period

exceeds $50,000 per unit-day of

maintenance moved.

(iv) A major forced outage at a unit

occurs outside of the November 1 to

March 15 period, and necessary periodic

maintenance occurs during the period of

forced outage.

If the Administrator determines that a

full 6 unit-weeks of maintenance during

the November 1 to March 15 period

should not be required, the owner or

operator shall nevertheless conduct that

amount of scheduled maintenance that

is not precluded by the Administrator.

Generally, the owner or operator shall

make best efforts to conduct as much

scheduled maintenance as practicable

during the November 1 to March 15

period.

[FR Doc. 91-23740 Filed 10-2-91: 8:45 am]

BILUNG CODE 6560-50-M