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Citation: 56 Fed. Reg. 50172 1991

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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 ofArizona to include a sulfur dioxide (SO 2)emission limit of42
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 itsmaintenance such that 6 unit-weeks ofmaintenance will be perfoi'med during the winter months.

This action is taken pursuant to sections 169A and 110(c) ofthe 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 ClassI areas. The timing of today's action is in accordance with the revised settlement agreement between EPA and Environmental Defense Fund (EDF)in EDFv. 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 ofsection 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 inDocket A-89-02, For background information, materials related to the development ofthe visibility protection program (40 CFR 51.300 etseq.) are available inDocket A-79--40. Also, materials related to the development ofthe 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 1:30p.m. to 3:30
p.m., Monday through Friday, at EPA's Central Docket Section, Office ofthe 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 ofAir Quality Planning and Standards (MD-15), Research Triangle Park, North Carolina 27711, (919] 541- 5350 orFTS 629-5350.

SUPPLEMENTARY INFORMATION:
I.Background

A. RegulatoryRequirements
Section 169A ofthe Act,42 U.S.C. 7491, sets as a national goal "the prevention ofany future,.and the remedying ofany existing, impairment ofvisibility in mandatory Class I Federal areas which impairment results from manmade air pollution." Mandatory ClassI Federal areas are certain national parks, wildernesses, and international parks as described in section 162(a) ofthe Act,42 U.S.C. 7472(a). Section 169A requires thatEPA 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 EPAto 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 (45FR 80084, codified at 40 CFR 51.300 etseq.). 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 Ivisibility 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 Ivisibility 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 oflandmarks or panoramas that extend outside ofthe 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 ofparticular 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. Under40 CFR 51.302(c)(1), an FLM
may certify to a State that there exists impairment of visibility in any mandatory Class IFederal 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 orcontribute" to any such impairment which is "reasonably attributable to that existing stationary facility," and analyze forBART 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

IThe EPA's 1980regulations implementing the statutory requirements ofsection 169A address visibility impairment that is reasonably attributable
to a single source orsmall group ofsources ("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 onmore .complex problems such as regional haze and urban plumes." id.at 80086.Today, inaccordance withthe 1980 regulations, EPA is taking regulatory action to remedy visibility impairment that is caused byNGS. The EPA is in theprocess ofestablishing the Grand Canyon Visibility Transport Commission as required by section 169B ofthe Act. The duties of that commission include making recommendations

on "promulgation ofregulations 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 

### thevisibility regulations, EPAmay act in place ofthe State pursuant to a FIP under section 110(c) ofthe 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 therights 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 Iimpairment has been certified, a State (orEPA ifthe State's visibility protection program addressing BART has not been approved, andEPA is acting in itsplace) must analyze for BART any specific existing stationary facility it identifies as a "reasonably attributable" source ofthe impairment. Pursuant to section 169A(b) oftheAct (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 of750 megawatts (MW) must be determinedpursuant to guidelines promulgated by the Administrator. This statutorily-required procedure for conducting a BART analysis is found in "Guidelines forDetermining Best AvailableRetrofit Technology Analysis for Coal-Fired Power Plants and Other Stationary Facilities" (EPA-450/3-80- 009bBART Guidelines). Acopy ofthis document maybe found inDocket A89-02A.

InDecember 1982, environmental groups, including EDF,filed a citizens, suitin the United States District Court fortheNorthern District ofCalifornia

2Section 110(c) requires EPA to promulgate FIP's whenever aState failsto submit an implementation plan(orportion thereof)which meets the requirements ofsection110, whenever the Administrator determines that aplan (orportion) Is not in accordance with the requirements ofsection 110, orwhenever the State failsto revise itsplan within60 daysafter notification bythe Administrator in accordance withsection

During the House ofRepresentatives' considerationof the Conference Report on the 1977 Amendments to the Clean Air Act.Congressman Rogers reiterated that the conferees had agreed that EPAwas toact where Statesfailed to carry out their dutiesin implementing the requirements of section 169A.The pertinent part ofCongressman Rogers' statement isasfollows:

'The conferees ***rejectedamotionto delete EPA's supervisory role undersection 110to assure that the required progresstowards that goal [the national visibilitygoal) will be achieved by the revisedState plan. IfaStatevisibility protection plan isnot adequateto assuresuch progress, the Administrator mustdisapprove thatportion ofthe SIP and promulgate avisibility protection plan under section 110(c).Thus. visibility protectionin mandatory federalclass Iareasremains anational commitment, which is nationally enforceable."

See Senate Comm. on Environment and Public Works,95th Cong. 2d. Sees. "ALegislative History of the Clean AirActAmendment of1977"No. 16, vol. 3at 311.320-21 (Comm. Print 1978). 

### alleging that EPAhad failed to perform

a nondiscretionary duty under section 110(c) ofthe Act, 42 U.S.C. 7410(c), to promulgate visibility FIP's forthe 35 States 'that, at that time,had failed to submit SIP'sto EPA as called for by the 1980 visibility regulations, EDFv.Reilly, No. C82-6850 RPA (N.D. Cal.). The State ofArizona was one ofthe 35 States that failed to submit arevised SIP to EPA.

TheEPA and theplaintiffs negotiated

a settlement agreement for the remaining Stateswhich the court approved by order on April 20, 1984. For

more information on details ofthe provisions ofthe original settlement, including a schedule ofactions byEPA,

see EPA's announcement ofthe agreement at 49 FR 20647 (May 16, 1984).

B.SettlementAgreement

To remedy the States' failure to 

### submit the necessary SIPrevisions during the time specified by the regulations, the settlement agreement replaced the original regulatory deadlines for visibility SIPprovisions with a rulemaking schedule agreed to by the parties and approved bythe court. This schedule required EPA to review the existing SIP's to determine any deficiencies, allow the Statesto cure those deficiencies, and to promulgate FIP's on a specified schedule for those States that still did not submit visibility SIPrevisions to EPA. Specifically, the first pert ofthe agreement required EPA
to promulgate FIP'swhich cover the monitoring and NSR provisions of40 CFR 51.305 and 51.307. TheEPA promu.gated its monitoring strategy for 23 States and itsNSR provisions for21 States, including Arizona, at 50FR 28544 (July 12, 1985), 51 FR 5504 (February 1, 1986), and 51FR 22937 (June 24, 1986). In 

### separate notices,EPA approved the SIP's ofthe other States with respect to monitoring and NSR.

The second part of the settlement agreement required EPAto determine the adequacy ofthe SIP's tomeet the remaining provisions ofthe visibility regulations and gave the States until December 1986 to submit additional

measures that would avoid the needfor

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 StateofAlaska hadsubmitted aSIPwhich

was ap roved onJuly 5,1983at 48 FR30623. 

### remedy any deficiencies on a specified schedule.

Pursuant to 40 CFR 51.302(c)(1), on November 14, 1985, theDepartment of theInterior (DOI) certified the existence ofvisibility impairment in all Class I

areas within itsjurisdiction in the lower 48 States. 

### On January 23, 1986, EPA determined that the SIP's of32 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, EPAand the plaintiffs negotiated revisions to the settlement agreement which extended the deadlines forState 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 EPAwhich supplemented its earlier certification ofvisibility impairment. The letter addressed the GCNP and identified the NGS, a coalfired power plantlocated near Page, Arizona, as aprobable source of impairment inthis Class Iarea. A copy ofthis letter may be found in Docket A89-02.



### Thirty-two affected States failed to submitvisibility SIPrevisions in response to thenotice ofdeficiency. Consequently, in accordance with the revised settlement agreement, on March 12, 1987 

### (52 FR 7802), EPA proposed to 

### disapprove the SIP's of32 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 inturn includes BART, longterm strategies, and other control strategies). Also in accordance with the agreement, on November 24, 1987 (52FR 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 forthese States. The EPA also determined that BART was unnecessary in 28 States because it could not reasonably attribute the visibility impairment ofmandatory Class IFederal 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 theneed

4A 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 forthe States ofArizona, Maine, Minnesota, and Utah to address certified visibility impairments in seven Class Iareas in these States which potentially could be reasonably attributed to a specific source pending acquisition and evaluation ofadditional technical information regarding the potential sources ofimpairment.

Because all ofthe 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, ofthe deadline for issuing a rulemaking proposal regarding the need for BART or other control

measures to remedy visibility impairments in three ofthe remaining Class I areas (MoosehornWilderness, GCNP, and Canyonlands National Park). With regard to theImpairment in the GCNP, EPAdelayed action in order to allow the National Park Service (NPS) time to analyze the data froma 1987 winter visibility attribution study, termed the Winter Haze Intensive TracerExperiment (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 ofthe seven Class I

areas. Based on monitoring conducted in these areas, EPA found that the visibility impairments werenot reasonably attributable to any specific

source. Therefore, EPAdetermined that it was not necessary to revise the FIP's for the States ofMaine, 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).

InApril 1989, EPAreceived a draft report onWHITEX from the NPS.5 

### Because ofthe delay in receiving this report, EPA believed that it lacked sufficient time to complete its analyses and issue a proposed rule by theAugust 31, 1989deadline. Accordingly, EPA and EDFfiled ajoint motion torevise the settlement agreement for a third time, which was approved by order ofthe
court datedJuly 6, 1989. Under this revision, there was no change in the deadlines for proposed action regarding Canyonlands National Park or

5Maim. at al.. "TheNational ParkService 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. TheEPA would proceed, on a preliminary basis, to issue a finding on reasonably attributable impairment by theAugust 31,1989 deadline. However, ifEPA did provisionally identify a specific source ofimpairment, it would solicit comments on that finding and would have additional timeto conduct a BART analysis. TheEPA was to issue a rulemaking proposal on the need for BART byFebruary 1,1990 unless, in response to comments, EPA rejected its proposed identification andinstead determined thatBART was unnecessary.

In accordance with thethird revision
to the settlement agreement, EPA published a notice ofproposed rulemaking on September 5,1989 (54FR 36948). Regarding Moosehorn Wilderness, EPA identified a source of the certified impairment butproposed that BART was unnecessary because the impairment would be adequately remedied by theretirement ofcertain existing emission units and the addition ofpollution controls on other units pursuant to a permit issued under the Act's prevention ofsignifigant deterioration provisions. As to Canyonlands National Park, EPA could notreasonably 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 notnecessary to address impairment in either theMoosehorn Wilderness or the Canyonlands National Park.

Regarding the GCNP, in the September 5,1989 notice, EPA preliminarily attributed several episodes ofwintertime visibility impairment to emissions from theNGS. In that regard, EPA reviewed the draft NPS report on WHITEX and concurred with the findings of theNPS.The EPA solicited comments on the merits ofits preliminary attribution finding.

OnNovember 28, 1989, the Salt River Project Agricultural Improvement and Power District (SRP), et al., and Alabama Power Company, etal., intervenors inEDFv.Reilly,filed a motion requesting a 1-year delay in the rulemaking schedule so that, among other things, the intervenors could conduct theirown 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 EPAto propose whether or not to require BART emission limits forthe NGS to remedy winter visibility impairment. The order also extended the deadline forfinal action on any proposal regarding BARTuntil October 1991 (6 months after theclose of thecomment period)."

C.Navajo Generating Station
TheNGS is a 2250,MW coal-fired
power plantlocated near Page, Arizona, approximately 20 kilometers from the northern boundary ofthe GCNP. The NGS is a baseload generating station consisting ofthree 750MW units which became operational between 1974 and 1976. The SRPis the operating agent for NGS which isjointly owned by the SRP,7 the Los Angeles Department of 

### Water and Power, theArizona Public Service Company, theNevada 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 fornitrogen oxides (NOX) control.

D.February 8,1991 Proposal

On February 8, 1991, EPA proposed to 

### revise the FIPfor Arizona to include emission limits to address the visibility impairment observed in GCNP. The following is a summary ofthe main issues discussed in the proposal notice.
1.Emission Limitation

TheEPA 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 ofthe 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 forNGS:

a. Acontinuous SO 2 

### emission limitation of0.50 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 (9thCir.). That appeal Ispending. In a Memorandum ofUnderstanding (MOU) discussed below,parties to this litigation have agreed, in light oftoday's action, to petition (a)theNinth Circuit to vacate the judgment below and remand the matter to the courtbelow with instructions to dismiss and (b) the District Court for the NorthernDistrict of California to dismiss EDFv.Reilly.No.C82-6850.

7The SRPowns 21.7 percent oftheNGS project for its own use and benefit, and 24.3percent for the

use andbenefit ofthe United States in accordance with the NGS project agreements. The term "NGS participants" is used in this notice to referto the parties which have rights andresponsibilities associated with the operation ofNGS and includes the owners,the operators, andthe 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 of0.10lb/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 SRPunder which it would testalternative control technologies, and ifone ofthe technologies met a minimum removal efficiency at a set cost, theNGS would install that. technology and operate it in the wintertime. Ifnone ofthe technologies met the test criteria, NGS would reduce its emissions by 70 percent (0.30 lb/ MMBtu emission limit)measured on an annualbasis by the year2000.

In addition, EPA requested comment

on whether another emission limitation

or a different averaging period may be

more appropriate.

2. Attribution



### As part ofthe February 8,1991 proposal, EPA reopened the comment period on its September 5, 1989 

### preliminary finding thatseveral episodes ofwintertime impairment in the GCNP was reasonably attributable
to NGS. The EPA notedboth in the September 1989 and the February 1991 notices that the findingwas not based

on any single analytical technique in the
NPSreport on WHITEX, but rather on the collection oftechniques performed by theNPS using WHITEX and other data. In detail, EPA explained that all of the techniques used by the NPS support the conclusion thatNGS 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 ofthe WHITEX study and discussed other visibility studies performed subsequent to WHITEX.

The National Research Council ofthe NAS reviewed andreported on the scientific methods used in theWHITEX 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 ofWHITEX which supported EPA's finding that, on

some days, NGS is a source ofvisibility impairment in the GCNP.8 Further, the

8The report found, for example, that the detection
atHopi Point (GCNP) ofthe unique tracerreleased 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 ofSO2 

### emissions from NGSis easily large enough to serve as the source ofthe 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. TheNAS report has been placed in the rulemaking docket.1 0 

### The SRPhas conducted another study known as theNavajo Generating Station Visibility Study (NGSVS). That study attempted to measure the degree of contribution by the NGS tovisibility impairment in the GCNP during the 1989-1990 winter season and to assess 

### the levl ofimprovement expected as a result ofreducing the SO emissions at 

### NGS. The SRPsubmitted a draft report describing that study and itsresults I during the public comment period on EPA's February 8,1991proposal. The NGSVS concluded that NGS emissions

were present at Hopi Point less frequently than during the WHITEX period. In addition, theNGSVS concluded that on days when NGS emissions were present, visibility impairment atHopi Point associated with those emissions was substantially less then the amount calculated in the NPSreport 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 ofits 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). 1 2 

### That analysis included consideration of the following: the costs ofcompliance, 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 ofcontrols.

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 ofthis report are available
from the National Academy Press, 2101 Constitution Avenue. NW., Washington, DC 20418.

IISonoma Technology, Inc.., "Navajo Generating Station Visibility Study," Draft Number 2, April 16, 1991.

"2U.S. EPA, "Draft Report on Best Available Retrofit Technology (BARTJ Analysis for the Navajo Generatig Station inPage, Arizona," January 1990. A copy ofthis 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 ofsuch controls, and other impacts ofinstalling and operating the controls. In the second part ofthe 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 ofinstalling and operating the controls defined in the control technology analysis. Because EPA was faced with some uncertainties ineach of the parts ofthe analysis, EPAbounded its results by giving low and high estimates. A detailed discussion ofthis analysis for NGS wasprovided inEPA's February 8, 1991 proposal.

To estimate the cost ofcontrolling the SO2 emissions atNGS, 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 ofthe more complicated tasks in the BART analysis was defining the relationship between the SO 2

### emissions at NGS and the visibility impairing sulfate in the GCNP. This relationship had to be addressed in order to estimate the degree ofimprovement in visibility that could be anticipated to result from theuse ofthe alternative SQ, control systems.Because ofthe complex terrain in and around the GCNP, EPA defined the source/impairment relationship using the ratio ofSO 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 ofthe uncertainties

IS Integrated Air Pollution Control System Costing Program, Version 3.0, copyright PEI and Associates, Inc., 1989.

14All 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 ofsourceimpairment 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 inVisibility expected
to occurin 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 ofreducing SO 2 emissions at NGS. The EPA stated in the proposal that this method is particularly relevant because human observers use contrast to make judgments ofhow atmospheric clarity changes withpollutant concentration. The contrast is defined as the percent difference between the brightness ofa scenic element and its background. The second technique was to analyze the seasonal average visual range change (see 56FR 5182Table 1].

Although not specifically addressed in the BART analysis, the proposal noted that EPA suspected that NGS emissions may contribute tovisibility impairment in the GCNP during other seasons ofthe 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 ofthe preliminary Regulatory Impact Analysis (RIA) (asrequired by Executive Order 12291) for the proposed rule.

4. Control ofParticulate 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 ofNO. 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 tovisibility impairment as

a general matter, upon the amount ofthe

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

### pollutants emitted by NGS, upon the proximity ofNGS to the GCNP, and upon the characteristics 

### oftheNGS plume, as shown by WHITEX and other studies, that increased emissions of these pollutants could resultin impairment in the GCNP. TheEPA noted that although the.NGS is not subject to any NO. emission limitations, SRPhas 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, of0.5 lb/MMBtu.

The EPA noted that PMemissions for the NGS are currently limited in two ways.The Arizona SIPhas both an emission rate limitation of0.06 lb/ MMBtu and an opacity limit of40 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 of40 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 forNGS.
5.Compliance Schedule

The EPA proposed to require that the emission limitation be achieved in three phases. Specifically, EPAproposed that the final emission limitation would need to be met on one unit byJanuary 1,1995;

on two units byJanuary 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 orpolicy, 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 ofSeasonal Controls

Part ofthe SRP proposal called for the

use ofseasonal controls. Therefore, EPA solicited comment on the use of seasonal controls. In theFebruary 8, 1991 notice, EPA noted that such controls would have to beboth technically and legallyjustified 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 ofcontinuous emission monitoring systems forcompliance determinations. b. Plant-wide averaging ofthe 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 ofthe transcript ofthe hearing is in Docket A-89-02A. As a result ofthe
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 ofthe 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 EPAinvited 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 Afterthe Close of theInitialCommentPeriod

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 forNGS consisting ofa 0.10 lb/MMBtu SO2 emission limitation (approximate to

a 90 percent control level) based on a rolling annual average and phased inby unit inNovember 1997, November 1998, and August 1999.In addition, under the agreement, NGS would shift its maintenance schedule-such that 6 unitweeks ofplanned maintenance would

occur between November 1 and March 15 each year. Under specific conditions, the Administrator ofEPA 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 ofthe State ofArizona also attended several ofthe 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

ofthe 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 forEPA'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 EPAproposed inFebruary 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 ofGeneral Counsel concluding that the outside parties' legal rationale in support oftheir 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 ofthe reopened
comment period in order to facilitate their ability to comment.

The EPA received 21 comments during the supplemental comment period. Eighteen ofthe 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 ofcertain visibility impairment episodes in GCNP and ispromulgating Federal revisions to the visibility implementation plan for Arizona to address those impairment episodes. As discussed below, EPAhas concluded that certain visibility impairment episodes in GCNP are traceable to NGS 

### and that NGS is a dominant contributor
to certain visibility impairment episodes. TheEPA finds today that a 0.10lb/MMBtu SO2 

### emission limitation (appro imately a 90percent emission reduction] based on a rolling annual averago and phased inby 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. Inparticular, itwill reduce by two-thirds the amount of pollution allowedunder theproposed rule.In addition, EPA finds that the final rulewill be significantly lesscostly than the proposal. Consequently, EPA further concludes that today's final action will provide a greater degree of "reasonable progress" toward thenational goal of remedying such impairment than would be provided by theFebruary 1991 proposal (see section 169A(b)(2) ofthe Act,42 U.S.C. 7491(b)(2)).

InEPA'sAugust 1991 supplemental notice requesting comment on the rulemaking alternative largely adopted in final form today, the Agency noted that SRP,GCT, and EDFhad recommended that thelegal rationale in support ofthis alternative be the requirement in section 169A(b)(2) ofthe 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 thematter and concluded, subject to any significant points that may be raised in thereopened comment period, that EPA could rely on the reasonable progressprovisions as the basis for this alternative. No significant adverse comments addressing the legal basis were received. Accordingly, EPA is adopting thisrationale as discussed in the supplemental notice.

Today's action is based upon the material in the docketincluding EPA's review and consideration ofall 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 ofthe significant comments received. Some responses are provided later in today's notice. Additionally, EPAhas prepared a document accompanying today's action, "Response to Public Comments: Proposed Revisions to Arizona Visibility FIP forNavajo Generating Station," which responds to comments. This document has been placed in Docket A89-02A. A. ImpairmentTraceabletoNGS

The EPA regulations promulgated on December 2, 1980 "[rlequire the control ofimpairment that can be traced to a single existing stationary facility or small group ofexisting 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) ofthe 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 ofNGS were observed in substantial quantities at Hopi Point during periods ofepisodic visibility impairment.

2. The NGS Is the predominate source ofSO2 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 NGSplume easily can, and frequently does, travel to GCNP.

5.The data and analyses in the docket show that sulfates arethe major contributor tovisibility impairment in GCNP.

The EPArecognizes that NGS is not the only source ofvisibility Impairment
at GCNP. Under the applicable statutory provisions and regulations, however, this isnot determinative 16 (see

16 Forexample, under section 169A(bl(2) ofthe Act, EPAis authorized to require visibility implementation plans containing "emission limits, schedules ofcompliance and other measures" necessary to makereasonable progress toward meeting the national visibility goal (see also40 CFR 51.302(c)). The national visibility goal, inturn, calls for theremedying of"any" manmade visibility impairment in Class Iareas (see section 169A(a)(1) and 40CFR 51.300(a)). As noted, EPA'sregulations implementing section 169A address visibility impairment that is reasonably attributable to a single source orsmall group ofsources and deferred action oncomplex problems such as regionalhaze (see generally, 45 FR80084 (December 2,1980)). Accordingly, as provided in the 1980 regulations, EPAmay remedy through emission limits, schedules ofcompliance, orother measures "any" visibility impairment that is reasonably attributable to an existing stationary source or small groupofsources (see also section 169A(c) ofthe Act and50 CFR 51.303 (authorizing an exemption from control requirements onlywhere aplant does not "byitself

orincombination with other sources" emitpollution "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 ofvisibility 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 alsomay 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. ControlTechnology

As part ofthe 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 ofany 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 willbe the economically proven control technology for meeting the 0.10 lb/ MMBtu emission limitation at NGS.

As a result ofnew information provided by SRP, EPA has revised and updated its cost estimates forthe installation and operation ofa wet FGD system. The revised estimated capital

cost and total levelized annual cost to
meet the emission limitation EPA proposed inFebruary 1991, in 1992 dollars, are $510 million and $106 million, respectively. The estimated capital cost and the total levelized annual cost, in 1992 dollars, tomeet the emission limitation promulgated today,

are $430 million and $89.6 million, respectively. Although not considered in these cost estimates, EPA expects that NGS willbe able to recoup a portion of the control costs by the sale of marketable allowances which it will receive as part ofthe allowance trading

contribute to significant impairment ofvisibility" in any Class Iarea and affirms, bynegative inference, EPA's broadrulemaking 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 TitleIV 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 forthe 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 higherlevel ofcontrol; compliance phased in by unit in 1997, 1998, and 1999;

an annual averaging period; and scheduled winter maintenance as a control strategy forNGS-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 forNGS 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 ofreasonable
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 ofNGS 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,

'= SeeDocket A-89- 2A specifically items IV-D164 and IV-D-375. and occur at othernearby mandatory Class IFederal areas. 19

The lower level ofNGS 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 ofhigh NGS contribution to severe episodic sulfate impairment events is limited by the known design reliability ofcurrent technologies which will achieve the required 0.10lb/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 ofthe control technology, and winter maintenance, taken together will, for the most part, prevent continuation ofsevere winter episodes caused by NGS. At the same time, the annual average lowers the

costs ofcompliance.

With respect tolong-term potential visibility impacts on the Golden Circle

area (the other Class I areas in the Colorado Plateau), there islittle 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. 2 0 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 ofNational Parks ofSulfur Dioxide Emission from Navajo Generating Station: Haze PuffModel Calculations for19"8-90."

20 See DocketA-89-02A. itemIV-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.EmissionLimitation

After reviewing the option recommended by SRP, EDF, and GCT in their MOU, EPAhas 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 ofthe national visibility goal incomparison to the February 1991 proposal. Thus, in today's action EPA is promulgating an SO 2 emission limitation of42 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

ora 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, EPAhas 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 ofcompliance, the time necessary for compliance, and the energy and non-air quality environmental impacts ofcompliance (see section 169A(g)(I) ofthe Act). Consideration ofthe pertinent statutory scheme and these specific factors has informed several aspects oftoday's action. Thus, for the policy and legal reasons stated,
an annual rolling average emission limitation is acceptable forthis case.Moreover, while this emission limitation is not expected tointerfere with attainment ofany otherrequirement ofthe Act, its adoption does not relieve NCS ofany responsibility for meeting any air quality standard, emission standard, orotherrequirement of the Act.

22 In the August 1991 supplemental notice, EPA published and requested comment onthe parties' August 8, 1991 MOU and associated documents. During thepublic comment period, the parties further clarified their agreement and submitted a revised versionoftheirMOU and recommended regulatory requirements to EPA. bothdocuments 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 ofemissions
at the plant. Therefore, after discussion with rupresentatives ofSRP, GCT, and EDF, EPA settled on a methodology that appropriately weights the emissions from each unit before calculation ofthe plant-wide average. The EPAhas used the daily electric energy generated as a weighting factor because that information is readily available for each unit and in this case isproportional 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 2emission 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 forthe 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 ofthe 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 ofthe daily electric energy generated and SO 2 emission rates will commence on:

1. November 19, 1997 for the first unit, 2. November 19, 1998for the second unit.

3.August 19, 1999 for the thirdunit.

23

A "boiler operating day" is specific foreach steam-generating unit at NGS and Is defined as a 24-hour calendar day (the period oftime 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 40CFR 60.41a: "u 24-hourperiod during which fossil fuel is combustcd in a steam-generating unitfor the entire 24hours." The EPA notes that the set ofprevious 365 boiler operating days for each unit will be unique to thatunit and thus the same set of calendar days probably will not be used for all three unitsin determining compliance. 

### TheNGS has the discretion to determine which of its three unitswill be controlled first and second.

In the discussion below, EPAhas recognized that certain difficulties encountered during the first year of operation ofa control system orthe catastrophic failure ofa control system may,based onEPA'sjudgment, warrant

a limited exclusion from compliance with the emission limitation, However,

as discussion below indicates, the control system, as ageneral matter, mustbe optimally operated consistent with good engineering practices to keep emissions at, orbelow, the emission limitation.

For eachunit, in determining compliance with the annual average emission limitation during the first year ofoperation ofthe 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 ormanufacturer's performance expectations.

2. Field installation including engineering orconstruction precludes equipment or systems fromperforming

as designed.

Theperiods during the first year tobe 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 ofthe 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 notfully operational. Whenever the time to be excluded exceeds a cumulative total of30 days for any control system, theNGS owner or operator must file a report within 15 days addressing the history of,and prognosis for, the performance ofthe control equipment.

In addition to the foregoing, the Administrator will exclude from the compliance determination for a unit any periods ofemissions from a unit for which the Administrator finds that the control equipment is out ofservice because ofcatastrophic failure of any control system which occurred for

reasons beyond the control of the NGS participants and operators and could not have beenprevented by good engineering practice. The Administrator will not exclude the period ifthe equipment failure was a consequence ot

a lack ofappropriate maintenance; of

### 50180 Federal Register / Vol. 56, No. 192 / Thursday, October 3, 1991 / Rules and Regulations

intentional or negligent conduct or omissions ofthe NGS participants or operators or the control system design, construction, oroperating contractors.

The 'final regulation requires that all equipment needed tocomply with this regulation to be optimally operated consistent withgood engineering practice tokeep emissions at or below the emission limitation. Theregulation also requires that following any control system outages, the system mustbe returned tofull operation as expeditiously aspracticable.

Thefinal regulation provides that continuous emission monitors mustbe installed to determine compliance with the emission limitation. This equipment mustmeetthe specifications listed in appendix B of40 CFRpart60, the quality assurance procedures in appendix Fof40CFRpart 60, and the requirements forestimating emission rate inng/J forlb/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 anoutage ofa control system occurs. The NGSmust notify the Administrator by telephone or bywriting within one business day ofany outage ofthe control systemneeded for compliance with the emission limitation and must submit a follow-up written report within 30 days ofthe repairs stating howthe repairs were accomplished and justifying the amount oftime taken for therepairs.

In theFebruary 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 SO 2 

### emission control equipment would cause increases inNO. and PM (which are limited by opacity limitations) emissions
at NGS which could affect visibility in GCNP. However, EPAdoes not have any evidence at this timethat NO, or PM emissions from NGS contribute

I' Forcertain requirements in today's action (e.g.. monitoring. reporting.recordkeeping. etc.), EPAhas relied on Itsregulations governing standards for performance fornew stationary sources. Those regulations have been relied onbecause they contain standardized procedures and requirements which apply tocoal-fired steam-generating units. In addition.EPA hasprovided that the NGS owners or operators must comply with therequirements relied

on in40 CFR part 00 as in effect today.This approach was agreed to andrecommended to EPA bySRP, UCT, andEDP in their August22.1991 MOU and associated documents. Atthis time. EPA believes that reliance on theregulations as they currently exist Isreasonable inthat they appear to provide adequate technical methods and procedures for determining and monitoringcompliance withthe S02 emission linuitation established today. significantly to visibility impairment in the GCNP. Further, the technology agreed to in the MOU will not increase NO, orPM 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 basedon asimple 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 ofthe NGSVS which included estimates ofNGS' 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 ofNGS' emissions over a long time period, indicated average wintertime improvements in therange of 4 to8 percent ifNGS 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 ofNGS' impacts for their respective study periods. Based solelyon 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 ofreducing emissions from NGS during certain meteorological conditions. Recent measurements of

26 Average ofthe total light scattering tothat part apportioned to NGS over the entire study period as found in appendix G ofthe 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. Forcertain periods analyzed in WHITEX and inNGSVS, NGS was shown to be thedominant contributor (more than 50 percent) to sulfates measured at Hopi Point.Ifcertain humidity andwind conditions occur during the periodwhen very high sulfate episodes are formed, reducing NGS emissions could result in increases in standard visual range up to 300percent. 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 forany given period.

Photographic data taken during WHITEX indicated that airflow'below therim ofthe canyon could result in higher visibility impairment due to trapping ofpollution. As a result, a new aerosol monitoring site atIndian Gardens (4,000feet below the rimofthe canyon) was established after the WHITEX study.This sitehas provided information since 1988 which confirms that the transport and conversion processes below therim ofthe canyon
are sometimes decoupled fromthe processes above the rim. Both NGSVS and the NPS report on WHITEX used the HopiPoint site, which is.above the rimoftheCanyon, as the basis for determining theNGS impact on GCNP. Data submitted during the comment period show thatvisibility below therim is impaired more often and to a greater degree than is the visibility above the rim at Hopi Point.2 7 

### 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 fromNGS to 0.10 

### lb/MMBtu should improve the winter seasonal average visibility above the rim ofthecanyon approximately 7 percent principally due to improvements during episodes. Analyses ofpeak incanyon sulfate levels during winter inversion episodes also lead EPAto 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 therim ofthe canyon. However, EPA did not quantify the expected visibilityimprovement below the rim ofthe canyon due to the limited amount ofdata and understanding ofthe air transport

21 See DocketA-89-.2A, itemsIV-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 ofthe

canyon. 

### F.

ScheduleofCompliance
As noted above, compliance with the emission limitation willbe phased-in by unit on the following schedule: 1.One unitby November 19, 1997. 2.Two units byNovember 19, 1998. 3.All units by August 19, 1999. The phasing in ofthe emission limitation will allow NGS to initiate operation of the control systems one at a time.

To ensure that NGS complies with the emission limitationby the dates specified.EPA has established a schedule ofcompliance 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 forthe first unit. Initiation of startup testing.

First unit

....................................... May 1997. Seond.................... May 1998. Third unit

........................ ....

Feb. 1999.



### theAdministrator may extend the interim deadlines ifNGS can demonstrate that compliance with the 

### final deadlines for compliance, stated above, willnotbe affected.
G.MaintenanceSchedule

The final regulation provides that by March 16, 1993, and every March 16th thereafter, the NGS owner oroperator 

### will prepare a long-term maintenance planfor NGS that maximizes winter down-time while accommodating the maintenance requirements for the other generatingfacilities on the NGSgrid. Theplan will cover theperiod from March 16 to March 15 ofthe next year and must provide atleast a full 6 unitweeks ofmaintenance forNGS in the November Ito 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 theWestern States Coordinating Council of the North American Electric Reliability Council to ensure adequate

reserve margin. The full 6 unit-weeks of winter maintenance neednot occur if any ofthe following circumstances arise.

1.There is no need for 6 unit-weeks of scheduled periodic maintenance in the March 16-March 15year covered by the plan.

2.The reserve margin on any electrical system served byNGS would fall to an inadequate level, as defined by the criteria referenced above. In such

case the scheduled maintenance may be moved autof the November 1to March 15 period.

3. Th. cost ofcompliance with this provision would be excessive. Costs of compliance would be considered excessive when the economic savings to the participants ofmoving NGS' maintenance out ofthe 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 offorced outage.

The NGS owner or operator must demonttrate to the satisfaction of the Administrator that one ormore ofthe
events listed above render unnecessary

orunreasonable a full 6unit-weeks of scheduled maintenance during the specificd winterperiod. 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 aspracticable during the winter period. IfNGS does
not conduct its scheduled winter maintenance (up to6 unit-weeks), it
mustreport to EPA why it did not do so.

When maintenance is being conducted on a unit, the unitwill not be in operation and therefore not emitting SO2 .Thus, the shifting ofNGS maintenance to the wintertime period will further reduce NGS SO2 emissions during the periodwhen 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 efmaking a degree ofreasonable
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 QualityReview

The installation and operation ofa 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 ofEnvironmental 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 ofany national ambient air quality standards. Ifthe 

### exhaust gas Is not reheated, the control
cost will be reduced significantly.

IfNGS were to select a wet FGD SO 2 

### control system, the water content ofthe plume would increase. Under certain conditions, a white steamplume will

occur as the water vapors condenses before it dissipates.This steamplume may bevisible near the stack. However, it will not cause any visibility impairment in GCNP or surrounding mandatory Class IFederal areas and will not interfere with the attainment of
any national ambient air quality standards. Such steam plumes are not subject to any State orFederal visual emission standards orregulations.

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 ofcontrols, and the benefit expected from the controls. In addition, EPA held a publichearing on March 18 and 19, 1991 during which EPA received comments on its February 1991 proposal.

Under section 307(d) ofthe Act, today's action must be accompanied by

a response to each ofthe significant comments, criticisms, and new data submitted in written or oral presentations during the comment period. The EPAhas carried out this duty. Moreover, modifications to the proposed rulehave been made in response topublic comments. The EPA's final control strategy forNGS largely embodies public comments received from representatives ofGCT, 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, EPArequested
comment on several control options including, but not limited to, the following rule elements and specific regulatory alternatives:

1.Emission limitations, including limitations rangingbetween 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 forplant-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 ofenvironmental 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 averagingperiod and a long compliance schedule.

During the initialpublic comment period,EPA received over 400 comments including the public hearing transcript. A summary ofthe significant comments, criticisms, and new data submitted in written orverbal presentations during thepublic commentperiod 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, EPAreceived 21 additional comments. Two commenters objected to requiring any additional pollution controls on NGS because ofthe uncertainty in the impairment attribution. Eighteen commenters generally supported the adoption ofa control strategy consistent with the MOU, although onecommenter expresssed some concerns about the compliance schedule and exemption fromwinter maintenance. One commenter objected because ofthe delayed compliance and the level of control.

The SRP, GCT,EDF,the Wilderness Society, theNational Wildlife Federation, and the Sierra Club have conditionally withdrawn prior comments that areinconsistent with the AugustMOU entered by representatives ofSRP,GCT, and EDF and associated recommendations to theAgency. In light ofthiswithdrawal, some ofthe comments discussed here and in the supplementary response to comments documentsplaced in the rulemaking docket are no longer pendingbefore the Agency and, clearly, no longer "significant" within the meaning of section 307(d) of theAct. Nevertheless, EPA has discussed them in order to help the public better understand today's action.

A. Attribution

The EPAreceived a large number of comments on its attribution ofvisibility impairment in the GCNP to NGS.These comments expressed avariety of opinions including statements that EPA har already made an attribution decision and that EPA shouldnotrevisit that decision, that more than adequate infcjimation was available tomake such

a decision and that it is clear from the record that certain visibility impairment

28JCM Environmental "Summary ofPublic Comments, Proposed Revision toArizona Visibility FIP'for Navajo Generating Station" July 1991.

29 See U.S. EPA. "Response toPublic Comments, Proposed Revisions to Arizona Visibility FIP." September1991. 

### episodes in GCNPare attributable to NGS, that EPAshould 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 ofthe impairment in the GCNP. In its February 1991 proposal,EPA reopened its
commentperiod on and exolicitlv requested public comment on its preliminary attribution decision. Therefore, EPA'sproposed 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 orderto estimate the expected improvements in visibility resulting from the installation ofthe controls.

In theFebruary 1991 proposal, EPA provided calculations ofthe relationship between reductions in SO2 emissions 

### fromNGS and the visibility at the GCNP. Thecalculations were based on the overall findings ofthe WHITEX report whichused several techniques to apportion NGS' contribution to sulfates and the resultinghaze at GCNP. The EPA calculated two measures of visibility improvements, one seasonal average change in standardvisual range and the other a distribution ofdays where control ofNGS would resultin several levels of contrast changes. The EPA received several comments that its calculations used to estimate the distribution ofdays when the reduction in SO2 emissions from NGS would result 

### inperceptible, quite noticeable, and very apparent change in contrast in GCNPwere in errorbecause the final contrast assessment did not take into account natural (Rayleigh) atmospheric scattering oflight. The EPAagrees that these calculations did not take into account Rayleigh scattering. However, EPA's seasonalvisual 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 duringthe comment period which has improved itsunderstanding of the source-impairment relationship. Based on this and other available information, EPAhas refined the sourceimpairment relationship and concluded that it is as described in the SourceImpairment discussion in "Today's Action" above.

C. EmissionLimitation

Individuals and groups that commented on the emission limitation generally requested that EPAadopt a requirement forthe maximum level of control orno controls at all.No
commenters supported the 50 percent control level. Some commenters supported an SRPproposal, 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 ofthe controls and/

orthe alleged lack ofa strong demonstrated source-impairment relationship.As discussed, EPA believes that an adequate source-impairment relationship does exist forEPA 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 fromNGS 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 itwill result in a greater emission reduction at a lower
cost.Further, as noted previously, EPA
mustbalance a number offactors 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 ofany future, and the remedying ofany existing, impairment ofvisibility in mandatory class IFederal

areas which impairment results from man-made air pollution." The EPA carefully has weighed. for example, the estimated cost ofcompliance 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 ofits delegated rulemaking authority under section 169A.

D.AveragingTime

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 (30days
to annual) averaging time stating that it would eliminate the need for expensive backup control equipment. The EPA's adoption ofthe control strategy, which includes an annual rolling average emission limitation, will eliminate the need forthe 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 wintermaintenance scheduling to

ensure maximum visibility protection.

E. ComplianceSchedule

Several commenters noted that section 169A ofthe Act requires that BART emission limitations be met within 5 years. Some ofthe commenters have since withdrawn thesecomments. 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 ofGeneral 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 ofsection 169A(b)(2). The requirements ofthat 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 ofthe value ofmarketable allowances when estimating the cost ofcontrol systems. The EPAreceived 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. CostofControls

Several commenters alleged that EPA may have overestimated the economic impact ofthe controls. They also noted that costs are quite small when divided up among the various consumers. Other
commenters alleged thatthe increased cost will have a significant Impact on the consumers. The EPAhas 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 ofcontrol. Even ifthe 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 otherrelevant factors EPA has concluded that the expected Improvements in the visibility In the GCNPjustify the estimatedcosts.

Several commenters noted that the recipients ofCAPwater face a greater price increase thanelectricity customers

or will otherwise bear a significant economic hardship as a result ofthe control costs oftoday's action. As discussed in theRegulatory Flexibility Act (RFA)section below, EPAcannot estimate every potential indirect cost of today's action. Nevertheless, EPA has carefully considered thepotential impacts oftoday's action on recipients ofCAPwater,including farmers receiving such water.The Central Arizona Water Conservation District (CAWUD) submitted an estimate of a 7 percent to 10percent increase in agricultural waterrates,resulting in an increased water cost ofnearly $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 ofa typical farm. At the present time,agricultural water in Arizona receives a substantial Federal subsidy. Current Federal policy callsfor phasing out the water subsidy. When the subsidy is eliminated, the Impact of the increased cost at NGS willbe an
even smaller percentage ofboth total variable cost and total water cost.The EPA has weighed and balanced the
costs oftoday's action, the expected visibility improvement, and other requisite considerations and concluded that today's control strategy, taken together, constitutes a reasonable exercise ofEPA's delegated rulemaking authority under section 169A of the Act.

H. Impaictson OtherClassIAreas
Several commenters noted the impact ofNGS on the other class Iareas In the region known as the "Golden Circle." Two ofthe commenters provided photographs and modeling to support their statements. The EPA agrees that NGS could contribute to thevisibility impairment in those other areas, but the data and modeling thatwere presented

were not adequate forEPA to use in making a definitive determination on attribution ofthe impairment in those

areas to NGS. However, the controls that are being required today will significantly reduce ifnot eliminate NGS' contribution to the visibility impairment in those areas. I ReasonalControls

In the February 1991 proposal. EPA requested comment on whether, as a policymatter, it should allow seasonal controls at NGS and whether, if technicallyjustified, seasonal controls would be legally permissible. Several commenters recommended that EPA adopt a control strategy forNGS 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/orcommented that as a legal matter seasonal controls could not constitute an emission limitation under section 169A. During the comment period, the GCTand 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. Forexample, a simple transport and transformation model ofNGS emissions overa 5-year period indicated impacts at GCNP in

seasons other thanwinter. While the degree ofvisibility impairment during these impacts Isless 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 Iareas between 60 and 80 percent ofthe time year-round. Forthe foregoing reasons, EPA concludes that year-round controls

are appropriate in this action. TheEPA's decision also Is consistent with the recommendations ofthe parties.While EPA'sregulations do not cover regional haze effects from existing sources, EPA alsonotes 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.MonetaryBenefits

Inthe February 1991 proposal. EPA noted that it was not legally required to estimate the monetary benefits associated withimproving visibility in the GCNP. However, as a check ofthe reasonableness ofits approach, EPA evaluated and considered thebenefit analysis developed as a part ofthe draft RIA for the proposed rule. TheEPA requested comment on its monetary benefits analysis and amonetary 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 formsno part of legal basis for today's action,EPA is not responding to those comments.
IV.EDFv. Reilly

Today's action regarding NGS completes EPA's obligations under the settlement agreement inEDF v. Reilly, No. C82-6850 (N.D. Cal.), and under the first round ofSIP/FIP planning called for in the visibility regulations.

V. Nonprecedential Effect ofThisAction

Today's promulgation is limited to the rulemaking requiring an SO 2 

### emission limitation forNGS in order to remedy a single-source visibility impairment in the GCNP thatis 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 orClass I areas.This isso because the outcome ofthis rulemaking has been highly dependent upon facts and circumstances that are unique to thisproceeding and thus doesnot apply to other cases. Forexample, thetracer studies and other analyses contained in the WHITEX and NGSVS reports that

are key to a showing thatimpairment at GCNP is traceable to NGS are not being approved for use in any other rulemaking addressing other potential

sources ofvisibility impairment. Should EPA orState 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 otherareas 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 ofimpairment 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 ofalternative S0 2 control-systems nor 

### the final emission limitbeing 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 todetermine ifa 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 ormore.

2. A major increase in costs orprices for consumers orindividual industries; Federal, State, orlocal government agencies; orgeographic 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 EPAjudged theFebruary 1991 proposed regulation for NGS to be a majorrule based on projected annualized costs potentially in excess of $100 million. TheEPA then prepared a preliminary RIA that included estimates ofcosts, benefits, and net benefits for three control options. Thepreliminary analysis, titled "Regulatory Impact Analysis of a Revision of the Federal Implementation Plan forthe State of Arizona to Include SO 2 

### Controls for the Navajo Generating Station," and an addendum, titled "Addendum to the Regulatory Impact Analysis ofa Revision ofthe Federal Implementation Plan forthe State ofArizona to Include SO 2

### Controls forthe Navajo Generating Station" are available in Docket A-89- 02A.

In light ofthe reduced estimated cost ofthis rule, the Office ofManagement and Budget (OMB] has exempted this action from the RIA requirements. Therefore, EPA did notfinalize the preliminary RIA.

B.Paperwork ReductionAct
This rule will impose a modest reporting burden on theparticipants 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. Section317(c)EconomicImpact Assessment

This action is taken pursuant to sections 169A and 110(c) oftheAct, and

a section 317(c) economic impact assessment may not be required. However, all ofthe analytical requirements ofsection 317(c) have been met. The section 317(c)(1) analysis of alternative regulations, and theimpact ofvarying the effective date, are essential considerations in promulgating thisrevision to the FIP forArizona. Each ofthe section 317(c) requirements are included in the BART analysis prepared by EPA. Portions ofthe economic impact
assessment are revisedin this notice based on additional information and
comments provided to EPA..

D.RegulatoryFlexibility 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

overpopulations ofless than 50,000. The requirement of preparing such is inapplicable, however, ifthe Administrator certifies that the rule will
not have a significant economic impact

on a substantial number of small entities (see 5U.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 ofthe participants ofNGS 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 utilityrates wouldbe' substantially less than 5percent.

Similarly, the emission limitation being established today does not have a direct impact on and will not apply to a substantial number ofsmall entities because none of the participants ofNGS 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 ofthe 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 ofReclamation, 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 ofsmall entities. Before discussing the comments, EPA notes that it cannot and isnot 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 forthe 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 of3.1 percent and 4.4 percent, respectively.30 The EPA estimated that ofthe six utilities receiving power from NGS, these two would experience the greatest electric
rate increases ifpower generation costs

were passed through completely to

consumers because both SRP and NPC rely on 25 percent ofNGS electricity for their total sales and each has a low
average cost/kWh relative to the other four participants. Further, EPA estimated that thesepercentage 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 ina 2.27 percent increase forits residential customers. The SRP also submitted comments on the February 1991 proposal in which it estimated that

a control strategy costing $90million would result in a 2.1 percent to 2.5 percent increase to its rate payers. These estimated increases are less than the 5percent 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 forfarmers receiving agricultural water from the CAP. This estimate translated into a $11/acre-foot increase (3 cents per 1000 gallons ofwater) raising the total annual variable costs for a 800-900 acre farm

3o See generally "DraftRegulatory Impact Analysis ofa Revision of theFederal Implementation Plan for the State ofArizona to Include SO2 Controls for the Navajo Generating Station." 

### (the size ofthe 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 1991proposal, a member ofthe Board of Directors ofthe CAWCD testified that their analysis concluded the NGS control costs would result in a $4.50per 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 forthe 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 ofits water delivery and, in turn, additional costs ofnearly $10,000 per 

### year for CAP water for a typical farmer, costs ofapproximately $3million annually on all ofits 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 furtherperplexing in that the option advanced in the August 1991 notice was less expensive than that identified inthe February 1991proposal. Because CAWCD's comments on costs

aregeneral and undocumented, EPA cannot check their derivation. In any case, both cost figures areless than half ofthat 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 2percent increase in total variable costs for the average farmer. The EPA has no reason to believe that the percentage increase in costs of
water formunicipal suppliers or Indian tribes will be substantially different fromthe economic impact on farmers purchasing CAP water.Further, as noted above, the owner ofNGSmay substantially mitigate the costs of today's action by selling SO allowances. This, in turn, shouldcurb any indirect costs incurred.

Finally, in commenting on EPA's February 1991 proposal, the Bureau of Reclamation (theBureau) generally, commented on EPA's conclusion that an initial RFA wasunnecessary by noting that testimony at thepublic hearing provided evidence ofadverse impacts

on small businesses, farmers, governmental entities, and Indian tribes. In itsonly example ofcost impacts, the Bureau commented that the agricultural
customers ofthe CAWCD could experience increases in their water rates ofapproximately $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 ofCAWCD could experience increases in water rates of approximately $10per acre-foot are inconsistent with CAWCD's own comments which suggested an impact of approximately $4.50 per acre-foot and, further, werenot substantiated. In addition, theBureau'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 inless than a 2percent increase in the total variable costs for the average CAWCD farmer.
As noted, EPAhas estimated the cost impacts on theresidential customers of SRP and NPC. Residential customers are usually the category ofconsumers bearing the greatest impact in cost increases because most utilityrate structures typically charge incrementally lessfor the more power thatis consumed. Further, as noted, EPA expects the impacts on the residential
customers ofNPC to be higher than any other customers ofthe NGS participants. Thus, EPA's estimate ofthe impact on NPC residential customers serves as a worst-case check on the potential electricity rate impacts on other potential customers. Theimpact on all potential small entities, including school districts,local governments, business establishments, not-for-profit enterprises, etc., shouldbe similar or smaller.Thus, not onlywere the Bureau's general claims aboutpotential impacts on small entities undocumented, butEPA believes its consideration ofthe impacts on residential rate payers affords a reasonable check ofthe potential impacts on other NGS electricity customers.

Accordingly, for all ofthe reasons stated,I hereby certify that the regulation being promulgated today will
not have a significant economic impact

on a substantial number ofsmall 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 Part52

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 ofwhich are subject to the emission limitation in paragraph (d)(2) ofthis section, that has accumulated at least 365 boiler operating days since the passage ofthe date defined in paragraph (d)(6) ofthis section applicable to it.

Administrator means the Administrator ofEPA orhis/her designee.

BoilerOperating Day for each ofthe boiler units at the Navajo Generating Station is defined as a 24-hour calendar day (the period oftime 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.

OwnerorOperator means the owner. participant in, or operator ofthe Navajo Generating Station to which this paragraph is applicable. Unit-Weekof Maintenance means a per'od of7 days during which a fossil fuel-fired steam-generating unit is under repair, and no coal is combusted in the unit.

(2) Emissionlimitation.No owner or operator shall discharge or cause the 

### discharge ofsulfur oxides into the atmosphere in excess of42 ng/J [0.10 pound per million British thermal units (lb/MMBtu)] heat input.

(3)Compliancedetermination. 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 inparagraph (d)(2) ofthis 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 theunit.

(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 ofthe daily S0 2 emission rate (computed according to paragraph (d)(3)(ii) ofthis section) and the daily electric energy generated (recorded according to paragraph (d)(3)(i) ofthis section) foreach 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 ofthe immediately preceding 365 boiler operating days willbe used for compliance determinations.

(v) Sum, for all affected units, the products ofthe daily SO2 emission rateelectric energy generated (as calculated according to paragraph (d)(3)(ii) ofthis section) forthe boiler operating days identified in paragraph (d)(3)(iii) ofthis section.

(vi) Sum, for all affected units, the daily electric energy generated (recorded according to paragraph (d)(3)(i) ofthis section) for the boiler operating days identified inparagraph (d)(3)(iii) of this section.

(vii) Calculate the weighted plantwide annual average S02 emission rate by dividing the sum ofthe products determined according to iv above by the

sum ofthe 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) ofthis section.

(4) Continuousemissionmonitoring. The owner or operator shall install, maintain, and operate continuous emission monitoring systems to determine compliance with the emission limitation inparagraph (d)(2) ofthis section as calculated in paragraph (d)(3) ofthis 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 of40 CFR part 60 in effect on October 3, 1991.

(5] Reportingrequirements. For each
steam generating unit subject to the emissionlimitation in paragraph (d)(2) ofthis section, the owner or operator:

(i) Shall furnish the Administrator written notification of the SO, oxygen, and carbon dioxide emissions according
to theprocedures found in40 CFR § 60.7 ineffect on October 3, 1991.

(ii) Shall furnish the Administrator writtennotification 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 orin writing within one business day ofany outage of the control system needed for compliance with the emission limitation in paragraph (d)(2) ofthis section and shall submit a follow-up written report within 30 days ofthe repairs stating how the repairs were accomplished and justifying the amount of time taken for the repairs.

(6) Compliancedates.The requirements ofthis 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 ofcompliance.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) ofthis section.

(ii) By January 1, 1995, initiate on-site construction orinstallation ofa control system for the first unit.

(iii) ByMay 1, 1997, initiate start-up testing ofthe 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 ofthe control system for the third unit. The interim deadlines will be extended ifthe owner or operators can demonstrate to theAdministrator that compliance with the deadlines in paragraph (d)(6) ofthis section will not be affected.

(8) Reportingon complianceschedule. Within 30 days after the specified date foreach deadline in the schedule of compliance (paragraph (d)(7) ofthis section, the owner oroperator shall notify the Administrator in writing whether the deadline was met. Ifit was not met the notice shall include an explanation why itwas not met and the steps which shall be taken to ensure future deadlines will be met.

(9) Exclusion forequipment failure duringinitial 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) ofthis section, periods during which one ofthe 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 ofcompliance with the emission limitation in paragraph (d)(2) ofthis 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 tobe excluded exceeds a cumulative total of 30 days for any control system for any affected unit, the owner or operators shall submit areport within 15 days addressing the history ofand prognosis 

### for the performance ofthe control system.

(10)

### Fxclusion forcatastrophic failure. In addition to the exclusion ofperiods allowed in paragraph (d)(9) of this section, any periods ofemissions from

an affected unit forwhich the Administrator finds that the control equipment or system for such unit is out of service because ofcatastrophic failure ofthe control system which occurred for reasons beyond the control 

### ofthe owner oroperators and couldnot have beenprevented by good engineering practices willbe excluded fromthe compliance determination. Events which are the consequence of lack ofappropriate maintenance or of intentional ornegligent conduct or omissions of the owner oroperators or the control system design, construction,

oroperating contractors do not constit'nte catastrophic failure.

(11) Equipmentoperation.The owner

or operator shall optimally operate all 

### equipment or systems needed to comply with the requirements ofthis paragraph consistent with good engineering practic3s to keep emissions at orbelow the emission limitation in paragraph (d)(2) of this section, and following outage; ofany 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 ofeach year starting in 1993, the owner or operator shall prepare and submit to theAdministrator a long-term maintenance plan forthe Navajo Generating Station which accommodates the maintenance requirements forthe other generating facilities on the Navajo Generating Station grid covering the period from March 16 to March 15 ofthenext year and showing at least 6unit-weeks of maintenance forthe Navajo Generating Station during theNovember 1to March 15 period, except as provided in paragraph (d)(13) ofthis section. This plan shall be developed consistent with the criteria established by the Western States Coordinating Council ofthe 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 theAdministrator in writing ifless than the full scheduled unit-weeks ofmaintenance 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) ofthis section.

(13)Exceptions formaintenance scheduling. The owner or operator shall conduct a full 6 unit-weeks of 

### maintenance in accordance with the plan required in paragraph (d)(12) ofthis section unless the owner or operator can demonstrate to the satisfaction ofthe Administrator thata full 6unit-weeks of maintenance during the November 1to March 15 period should notbe required because ofthe following:

(i)There is no need for6 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 inparagraph (d)(12) ofthis section.

(iii) The cost ofcompliance with this requirement would be excessive. The
cost of compliance would be excessive when the economic savings to the owner

oroperator ofmoving maintenance out ofthe November 1toMarch 15 period exceeds $50,000 per unit-day of maintenance moved.

(iv)Amajor forced outage at a unit

occurs outside ofthe November 1to March 15 period, and necessary periodic maintenance occurs during the period of forced outage. Ifthe Administrator determines that a full 6 unit-weeks ofmaintenance during the November 1to March 15 period should not be required, the owner or operator shall nevertheless conduct that amountof scheduled maintenance that isnot precluded by the Administrator. Generally, the owner or operator shall make best efforts to conduct as much scheduled maintenance as practicable during the November 1toMarch 15 period.
[FRDoc. 91-23740 Filed 10-2-91: 8:45 am]

BILUNG CODE 6560-50-M