P.1 

OAR Box 1865 

Prepped by Charmelle Mathews 

Document Number: 

171) VIII-A-1 

Docket Number: 

A-83-27 

Printed 12/3/2008 3:22:23 PM Sheet 171 of 198 
P.2 

« A'*w* 

A-83-27 

Friday 

January 13, 1989 

VII-A- l 

Part V 

Environmental 

Protection Agency 

40 CFR Part 60 

Standards of Performance for New 

Stationary Sources; Industrial-Commercial 

Institutional Steam Generating Units; 

Proposed Revision of Rule and Denial of 

Petitions for Reconsideration 
P.7 

1610 Federal Register / Vol. 54, No, 9 / Friday, January 13, 1989 / Proposed Rules 

nitrogen oxides emission limits under 

§§ 60.42b, 60.43b, and 60.44b. shall 

submit to the Administrator the 

performance test data from the initial 

performance test and the performance 

evaluation of the CEMS using the 

applicable performance specifications in 

Appendix B. The owner or operator of 

each affected facility described in 

§§ 60.44b(j) or 60.44b(k) shall submit to 

the Administrator the maximum heat 

input capacity data from the 

demonstration of the maximum heat 

input capacity of the affected facility. 

**** * 

(e) For an affected facility that 

combusts residual oil and meets the 

criteria under 99 60.46b(e)(4), 60.44b(j), 

or 60.44b(k), the owner or operator shall 

maintain records of the nitrogen content 

of the residual oil combusted in the 

affected facility and calculate the 

average fuel nitrogen content on a per 

calendar quarter basis. The nitrogen 

content shall be determined using 

ASTM Method D3431-60. Test Method 

for Trace Nitrogen in Liquid Petroleum 

Hydrocarbons (IBR—see 9 80.17), or fuel 

suppliers. If residual oil blends are being 

combusted, fuel nitrogen specifications 

may be. prorated based on the ratio-of 

residual oUs of different nitrogen '-

content in the fuel blend. 7 

• • * '» • 

(g) Except as provided under 7 

paragraph (p) of this section, the owner 

and operator of an affected facility 

subject to the nitrogen oxides standards 

under 160.44b shall maintain records of 

the following information foreach steam 

generating unit operating day: 

• • • • • 

(p) The owner or operator of an 

affected facility described in 99 B9.44b(J) 

or 60.44b(k) shall maintain records of 

the following information for each steam 

generating unit operating day: 

(1) Calendar date. 

(2) The number of hours of operation, 

(q) The owner or operator of an 

affected facility that meets the criteria 

under 99 60.44b(j) or 60.44bfk) shall 

submit to the Administrator on a 

quarterly basis: 

(1) Results of any nitrogen oxides 

emission tests required during the 

quarter, 

(2) The annual capacity factor over 

the previous twelve months, 

(3) The average fuel nitrogen content 

during the quarter, if residual oil was 

fired; and. 

(4) If the affected facility meets the 

criteria described in 9 60.44b(j)» ihe. 

hours of operation during the quarter 

and the hours of operation since the last 

nitrogen oxides emission test. 

|FR Doc. 89-700 Filed 1-12-89; 8:45 am| 

BIUJNO COOC SMO-SO-M 

40 CFR Part 60 

(AO-fRL-3504-9) 

Standards of Performance for New 

Stationary Sources; IndustrtatCommarewHnstrtutJonaJ Steam 

Generating Units 

AOINCV: Environmental Protection 

Agency (EPA). 

ACTION: Denial of petitions for 

reconsideration. 

SUMMARY: New source performance 

standards (NSPS) for new, modified, and 

reconstructed industrial-commercialinstitutional steam generating units with 

heat input capacities of more than 28 

MW (100 million Btu/hour) [other than 

those subject to Subpart Da) were 

promulgated on November 25,1986 (51 

FR 42788). as Subpart Db of 40 CFR Part 

60. These standard* limited emissions of 

particulate matter (PM) from industrialcommai-dal-institutional steam

 ; 

generating units firing coal, wood'and

 ; 

municipal solid wasteland nitrogen 

oxides (NOJ emissions from steam 

generating units firing natural gas. oil 

coal and waste by-product fuels. 

Additional standards promulgated on 

December 16.1987 (52 PR 47826), (united 

emissions of sulfur dioxide (SOi) from 

industrial-commercial-institutional 

steam generating units firing coal and 

oil, and PM emissions from units firing 

oil. 

Petitions requesting reconsideration of 

the standards of performance 

promulgated on November 25.1986* 

were submitted to the Agency in 

January 1987 by the Council of Industrial 

Boiler Owners (CffiO). Utility Air 

Regulatory Group (UARG). and the: 

owners of the William H. Zimmer . 

Generating Station (Cincinnati Gas aV 

Electric Company, Columbus and 

Southern Ohio Electric Company, and 

the Dayton Power and Light Company, 

referred to hereinafter as the Zimmer 

owners). Petitions requesting 

reconsideration of the standards of 

performance promulgated on December 

18.1987, were submitted to the Agency 

in February. March, and May1988. by 

CIBO, Hawaiian Electric Company 

(HECOL the Zimmer owners* and th» . 

American Paper Institute (API) together 

with the National Forest Products 

Association (NFPA). 

The issues raised by these petitioner 

do not meet the criteria for ' 

reconsideration of the rule as set out in 

section 307(d)(7)(B) of the Clean Air Act 

(CAA or the Act). The petitioners 

neither raised new objections that were 

impractical to present during the 

specified comment period nor presented 

new material of central relevance to the 

outcome of the rule. Because these 

petitions do not provide substantial 

support for revising the standards of 

performance promulgated on November 

25.1986, and December 18,1987. they 

are being denied in today's notice. 

However, using his discretionary 

authority to reconsider and amend a 

rule, the Administrator has decided that 

sufficient reason exists and, therefore, is 

proposing revisions to parts of the NO, 

rule. (The rationale for this decision is 

explained more fully in a separate 

Federal Register notice.) These proposed 

revisions are discussed elsewhere in 

today's Federal Register. 

OA-rn: The denial of the petitions to 

reconsider these standards is a final 

action under sections 307(b)(1) and 

307(d)(7)(B) of the CAA. Review of the 

denial is available only by the filing of t 

petition for review in the U& Court of 

Appeals for the District of Columbia 

within 60 days of today's publication, as 

provided in section 307(b)(1). 

AOOWSSStS. Docket Nos. A-79-02 (PM/ 

NOJ and A-83-27 (SOi) are available 

for public inspection and copying 

between 8*00 a jn. and 4:30 pjn., Monday 

through Friday, at Central Docket 

Section. South Conference Center, Room 

4. Waterside Mall. 491M Street SW.. 

Washington. DC 20469. A reasonable fee 

may be charged for copying. 

POfrPIMTMIR WsKNIMATIOM CONTACT: 

For further Information contact Mr. Fred 

Porter [(919) 541-5251], Standards 

Development Branch, Emission 

Standards Division (MD-13). UA 

Environmental Protection Agency, 

Research Triangle Park, North Carolina 

27711. 

SUmiMiMTAItV WrOWMATlOW: 

Standards of performance for PM and 

NO, emissions from industrialcommercial-institutional steam 

generating units were promulgated on 

November 25.1966 (51 FR 42768), and for 

SOi emissions on December 16,1987 (52 

FR 47828). Subsequently, seven groups 

petitioned the Administrator pursuant to 

section 307(d)(7)(B) of the CAA to 

reconsider certain requirements of these 

standards. 

These standards of performance 

implement section 111 of the Clean Air 

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P.8 

Federal Register / Vol. 54, No. 9 / Friday, January 13, 1989 / Proposed Rules 1611 

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Act and are based on the 

Administrator's determination that 

industrial-commercial-institutional 

steam generating units cause or 

contribute significantly to air pollution 

which may reasonably be anticipated to 

endanger public health or welfare. 

Industrial-commercial-institutional 

steam generating units, as a source 

category, are the second largest 

stationary source of PM, NO,, and SOi 

emissions from fuel combustion in.the 

nation, ranking only behind electric 

utility steam generating units. Further, 

they were the highest ranked source of 

PM and SOj emissions and the second 

highest ranked source of NO, emissions 

in the NSPS priority list adopted in 1980. 

The standards, as promulgated, reflect 

the Administrator's determination of the 

reduction in emissions (i.e., PM, NO,, 

and SOj) achievable by the best 

demonstrated system of continuous 

emission reduction considering costs, 

nonair quality health and environmental 

impacts, and energy requirements. [See 

CAA section 111(a)(1)(C).) The basis for 

specific components of the standards as 

promulgated were set forth in the 

preambles to the final rules (51 FR 47268 

and 52 FR 47826) and the various 

background documents referred to in the 

promulgation notices and contained in 

the record. In certain cases, specific 

percentage reduction requirements were 

determined to be unreasonable. 

Emission limits, however, remain 

applicable. 

By and large, the petitions submitted 

by the parties challenge various 

individual pieces of data, conclusions 

made by the Agency, or interpretations 

of the data. For the most part, the 

petitions simply restate or expand on 

issues raised and considered during the 

comment period or present issues that 

could have been raised during the 

comment period. To the extent that new 

issues are raised (e.g., the effect of the 

"new boiler survey" on the PM 

standards), the petitioners' contentions 

are either without merit, or even if true, 

do not affect the outcome of the rule. 

Although most of the contentions raised 

in the petitions could be rejected 

summarily, the Agency, in the notice 

below, has endeavored to provide a 

comprehensive response to the 

contentions. 

Three groups petitioned for 

reconsideration of the promulgated PM/ 

NO, standards. CIBO (Docket No. A-79-

02. Docket Item VI-D-2) sought 

reconsideration on the basis that the 

interrelationship with the SOi standards 

was not considered, the environmental 

and economic impacts of the standards 

were overstated, new information 

gathered in the Agency's own "Survey 

of New Industrial Boiler Projects 1981-

1984" (referred to hereinafter as the 

"new boiler survey") (Docket No. A-83-

27, Item IV-A-4) was not considered, 

and certain aspects of the Industrial 

Fuel Choice Analysis Model (IFCAM) 

were not valid. The Zimmer owners 

(Docket No. A-79-02, Docket Item VI-D6) petitioned for reconsideration of the 

PM/NO, standards on the basis that 

NO, limits on electric utility auxiliary 

steam generating units are unreasonable 

and distillate oil NO, standards cannot 

be achieved. UARG (Docket No. A-79-

02, Docket Items VI-D-1 and IV-LM) 

petitioned for reconsideration on the 

basis that NO, limits on electric utility 

auxiliary steam generating units are 

unreasonable. 

Five groups petitioned for 

reconsideration of the promulgated SO» 

standards. CIBO (Docket No. A-83-27, 

Item VI-A-1) petitioned on the basis 

that the standards are inconsistent with 

the 1977 amendments to the CAA, 

national energy policy was not 

considered, the performance of fluidized 

bed combustion (FBC) and lime spray 

drying flue gas desulfurization (FGD) 

systems was not demonstrated, new 

information on waste disposal impacts 

was discovered after the comment 

period closed, the exemption from 

percent reduction requirements for 

noncontinental areas is arbitrary, new 

analyses made available after proposal -

of the standard (especially information 

from the "new boiler survey") were not 

given sufficient consideration, and 

informal vendor statements were used 

to support the requirement for 90 

percent SO*, reduction. The Zimmer 

owners (Docket No. A-83-27, Item VIA-4) petitioned on the basis that the 

impacts of a 130 ng/) (0.30 lb/million 

Btu) heat input emission limit for SOa on 

two oil-fired electric utility auxiliary 

steam generating units at the Zimmer 

Station are unreasonable. HECO 

(Docket No. A-83-27, Item VI-A-5) 

requested reconsideration on the basis 

that the impacts of a 130 ng/J (0.30 lb/ 

million Btu) heat input emission limit for 

SOi on oil-fired steam generating units 

in Hawaii are unreasonable. API and 

NFPA (Docket No. A-83-27, Item VI-A6) sought reconsideration on the basis 

that the lack of provisions for start-up, 

shutdown, and malfunction is 

unreasonable. 

The next section of today's notice 

discusses the content of each petition 

relative to the criteria set forth in 

section 307(d)(7)(B) of the CAA for 

requiring the Administrator to convene a 

proceeding to reconsider the 

promulgated standards. Following that 

section, the notice addresses the 

technical merit of each issue raised in 

the petitions. 

This notice is organized as follows: 

I. Review of Petitions for Reconsideration 

Under Section 307 of the Clean Air Act. 

A. Criteria for Reconsideration Under 

Section 307. 

B. Summary of PM/NO, Reconsideration 

Petitions. 

1. UARG. 

2. Zimmer Owners. 

3. CIBO. 

C. Summary of SO, Reconsideration 

Petitions. 

1. CIBO. 

2. Zimmer Owners. 

3. HECO. 

4. API/NFPA. 

II. Petitions Submitted Concerning the PM/ 

NO, Standards 

A. Achievability of the PM/NO, Standards. 

1. Achievability of the NO" Standards by 

Distillate Oil-Fired Electric Utility Auxiliary 

Steam Generating Units. 

2. Special Monitoring Problems Associated 

with Electric Utility Auxiliary Steam 

Generating Units. 

B. Interrelationship of PM/NO, and SO, 

Standards. 

1. Effect of SOJ Control Techniques on PM/ 

NO,. 

2. Achievability of NO, Standards by 

Pulverized Coal-Fired Units When Using 

Back-Up Fuel to Meet SOi Standards. 

C. Projected Environmental and Economic 

Impact 

1. Overstatement of Impacts. 

2. Legal Basis for and Economic Impacts of 

Controls on Electric Utility Auxiliary Steam 

Generating Units. 

D. "New Boiler Survey". 

E. IFCAM National Impacts Model. 

III. Petitions Submitted Concerning the SO, 

Standards 

A. Legal Basis for Establishing the SO, 

Standards. 

1. Consistency of SO, Standards with 

Congressional Intent. 

2. Impacts of the SO, Standards on the 

National Energy Policy. 

B. Projected Economic Impacts. 

1. Cost Effectiveness of a 130 SO, ng/| (0.30 

lb SOi/million Btu) Heat Input Emission Limit 

on Electric Utility Auxiliary Steam 

Generating Units at the Zimmer Owners' 

Generating Station. 

Z. Exemption for Noncontinental Areas. 

3. Failure to Analyze Economic Impacts on 

the Paper Industry. 

4. Inadequate Analysis of the Economic 

Impact of Start-up, Shutdown, and 

Malfunction Provisions. 

5. Legal Requirement for Consideration of 

Start-up, Shutdown, and Malfunction Costs. 

6. Availability of 130 ng SCs/I (0.30 lb SO,/ 

million Btu) Oil in Hawaii'. 

7. Need for New Oil Transportation System 

in Hawaii. 

8. Increased Use of Large Steam Generating 

Units or Gas Turbine Generators in Hawaii. 

9. Economic Impacts of Firing Low Sulfur 

OU in the Hawaiian Outer Islands. 
P.9 

1612 Federal Register / Vol. 54, No. 9 / Friday, January 13, 1989 / Proposed Rules 

C. Post-Proposal Developments 

1. New Docket Material. 

2. Analysis of Ihe "New Builer Si-rvey". 

3. Reevaluation of SO, Emission 

Reductions. 

4. Information on Impacts of Waste 

Disposal. 

5. Ability of FBC and FGD System to 

Achieve 90 Percent SO2 Reduction. 

6. Use of Vendor Statements to Support 90 

Percent SO, Reduction. 

IV. Summary 

I. Review of Petitions for 

Reconsideration Under Section 307 of 

the Clean Air Act 

A. Criteria for Reconsideration under 

Section 307 

Review of these petitions for 

reconsideration was carried out 

according to the procedures of section 

307 of the Clean Air Act. Section 

:W(d)(7)(B) provides that: 

[ijf the person raising an objection can 

demonstrate to the Administrator that it was 

impracticable to raise such objection within 

(the comment period) or if the grounds for 

such objection arose after the period for 

public comment (but within the time specified 

for judicial review) and if such objection is of 

central relevance to the outcome of the rule, 

Ihe Administrator shall convene a proceeding 

for reconsideration of the rule. . . . 

As the relevant House report explains, 

the purpose of section 307(d)(7)(B) is to 

provide the Agency an opportunity "to 

pass on the significance of the [new] 

materials and determine whether 

supplementary proceedings are called 

for or not." (See "Legislative History of 

the Clean Air Act Amendments of 1977," 

Volume 4, p. 2790.) 

Objections are of central relevance 

only if they provide substantial support 

for the argument that the standards 

should be revised. [See Denial of 

Petition to Revise NSPS for Stationary 

Gas Turbines, 45 FR 81853 (December 

11,1980); Response to Petition for 

Reconsideration and Final Amendments, 

NSPS for Petroleum Dry Cleaners. 50 FR 

49022, (November 27,1985).] Using the 

section 307(d)(7)(B) criteria, each of the 

seven petitions was reviewed to 

determine whether material of central 

relevance to the rule was presented that 

could not have been presented during 

the comment period. For reasons 

summarized below and detailed later in 

this notice, it is apparent that none of 

the petitions presents this kind of 

material. In a separate notice in today's 

Federal Register, however, the 

Administrator is exercising his 

. discretionary authority to propose 

revised rules for monitoring NO, 

emission from very low capacity factor 

steam generating units.1 

fl. Summary of PM/NO_ 

Reconsideration Petitions 

1. UARG 

UARG submitted a petition 

contending that EPA did not respond to 

the specifics of arguments it had made 

on the proposed rule. Further, UARG 

supplemented this petition with 

arguments that no standards should be 

imposed on very low capacity factor 

utility auxiliary steam generating units. 

UARG also sought deletion of the 

monitoring requirements on the grounds 

that the requirements cannot be applied 

readily to units that are used 

infrequently. 

These arguments do not compel 

reconsideration under section 307. First, 

a claim that EPA's response to 

comments was incomplete does not 

trigger section 307 reconsideration. 

Second, the information provided in 

UARG's "supplement" could have been 

provided during the comment period. 

The same is true of the arguments 

concerning monitoring. UARG's 

comments are discussed in Section m 

below. 

2. Zimmer Owners 

The Zimmer owners argued that EPA 

failed to address their comments on the 

proposed standards. In a supplement 

dated June 29,1987,7 months after the 

standards were promulgated, the 

Zimmer owners argued that the 

standards should not apply to utility 

auxiliary units for legal and economic 

reasons. 

As the Zimmer owners themselves 

seemed to recognize, their 

reconsideration comments generally 

repeated and expanded on arguments 

raised during the comment period. Such 

comments do not compel 

reconsideration under section 307. The 

1

 Section 4(d) ot the Administrative Procedure 

Act (APA). VS.C. 553(e). states. "Each agency shall 

give an interested person the right to petition for 

issuance, amendment or repeal of a rule." Although 

Section 4(d) of the APA also establishes a right to 

petition for administrative reconsideration, thai 

provision almost certainly does not apply to 

petitions for reconsideration of regulations that are 

promulgated pursuant to tha rulemaking provisians 

of Section 307(d) of the Clean Air Act. See section 

307(d)(l)(N). 42 U.S.G 7607(d)(l)tN). ("The 

provisions of section 553 through 557 * * * of Title 

5 of the United States Code shall not except aa 

expressly provided in this subsection, apply to 

action 10 which this subsection applies.**) In any 

event, the criteria for evaluating a petition for 

reconsideration under APA are essentially the same 

as those for section 307(d)(7HB) petitions. See 

Denial of Petition* to Revise NSPS far Stationary 

Gas Turbines. 45 FR 81653-54. and decisions cited 

therein. 

Zimmer owners' comments are 

discussed in Section III below. 

3. CIBO 

CIBO argued that two post-proposal 

developments in the SOa proceeding 

compel reconsideration of the PM/NO, 

rule under section 307. The two 

developments were EPA's proposal of 

an "interrelated" SOa standard after 

proposal (but before promulgation) of 

the PM/NO, standards and the 

imminent (in early 1987) completion of a 

"new boiler survey" in the SOa 

rulemaking. 

These developments do not compel 

reconsideration under section 307 

because they do not constitute 

information of central relevance to the 

outcome of the PM/NO, rulemaking. 

EPA has long recognized and taken into 

account the interrelated character of the 

PM/NO, and SOi rules. CIBO's 

argument, therefore, does not provide 

new information. The only respect in 

which the argument could be considered 

new is in CIBO's conjecture that the 

NO, standard could be violated in steam 

generating units designed for firing 

pulverized coal (PC) when using natural 

gas or oil. As explained below in 

Section III, however, EPA believes that 

compliance with the NO, standards can 

be readily accomplished by such units, 

and CIBO has provided no data to 

support-its comments. CIBO's comments 

on the interrelationship of the PM/NO, 

and SOa rules are discussed in Section 

III below. 

CIBO's claims that the projections of 

new units were too high and its 

conjectures regarding the "new boiler 

survey" do not compel reconsideration 

under section 307. As explained in 

Section III below, new projections of the 

absolute number of new and 

replacement steam generating units are 

informative, but far less important in 

regulatory analysis than the relative 

balance between costs and benefits. 

When deciding whether or not to 

regulate, it is the relative balance 

between costs and benefits that is of 

primary importance rather than the 

absolute numbers. However, even with 

lower projections of the number of new 

units, the emission reductions achieved 

by the standards are significant. 

Conjecture regarding the methods of the 

"new boiler survey" is also not a basis 

for mandatory reconsideration absent 

compelling indications that.the survey 

methods affected the results. CIBO's 

critiques are not, therefore, of central 

relevance to the outcome of the rule. 
P.10 

Federal Register / Vol. 54, No. 9 / Friday, January 13, 1989 / Proposed Rules 1613 

C. Summary of SCh Reconsideration 

Petitions 

1. CIBO 

CIBO argued that (1) the S02 

standards are inconsistent with the 1977 

amendments to the CAA, (2) national 

energy policy was not considered, (3) 

EPA erroneously analyzed the results of 

a "new boiler survey," (4) the "new 

boiler survey" produced important new 

information, (5) post-proposal waste 

disposal information showed that flue 

gas desulfurization (FGD) on coal-fired 

units is not cost effective, (6) postproposal fluidized bed combustion (FBC) 

and spray dryer information did not 

show that they constitute "demonstrated 

technologies, (7) EPA did not provide 

notice of the extent of its reliance on 

vendor guarantees, and (8) EPA should 

have extended its unanticipated 

exemption from percent reduction 

requirements for noncontinental areas to 

the continental United States. CIBO 

argued that these post-proposal 

developments compel reconsideration 

under section 307(d)(7)(B). 

This is not the case. The issues of 

consistency with the 1977 amendments 

to the CAA and national energy policy 

were raised and discussed at length 

prior to proposal as well as during the 

comment period. [See e.g.. "Background 

Information Document" (BID), Volume 

4.] Such comments, therefore, do not 

compel reconsideration under section 

307. 

Concerning the analysis of the "new 

boiler survey," EPA surveyed steam 

generating unit sales from 1981 to 1984 

to determine why new steam generating 

units are installed, what percentage of 

recent sales were for replacement, how 

sales might be related to increased cost, 

and the impact of new units on overall 

SO2 emissions. The survey was 

conducted to respond to CIBO 

comments that the great majority of new 

units replace existing units and that the 

NSPS would prompt owners to delay 

purchasing replacement units. CIBO 

suggested that EPA's analysis of the 

"new boiler survey" is faulty and argued 

that had EPA correctly analyzed the 

survey, the outcome of.the rule would 

have been different.2 

Again, this is not the case. The 

findings of the survey indicate that 

although replacement was the primary 

reason for many new units, a roughly 

equal number of units are installed for 

2

 That EPA was going to conduct the "new boiler 

survey" was noted in the June 19,1988. notice of 

proposed rulemaking (51 FR 22384). Notice of tha 

availability of the study was sent to all commenters 

in April 1987, informing them that new analyses 

were being added to Docket A-83-27. 

new applications. The survey also found 

that the decision to build most of these 

new application units was not sensitive 

to cost increases in the range expected 

to result from the new rules. Findings 

from the survey also indicated that 

many existing units would continue to 

be used alongside the replacement units. 

In its petition, CIBO hypothesized that 

the answers received from the survey 

might have been different if the survey 

had asked whether the unit would be 

built if air pollution control equipment 

were required. However, CIBO provided 

no details to support this conjecture. 

Unsupported conjecture does not 

provide a basis for reconsideration 

under section 307. As discussed in 

greater detail in Section IV below, the 

amount, not the origin, of costs seems 

relevant to elasticity of sales as a 

function of costs. The replacement rate 

may affect the number of unit sales, but 

in the final analysis—and absent 

volume price decreases—the 

relationship between control costs and 

absolute emission reductions is more 

relevant to standard setting. 

CIBO also argued that, apart from 

costs, reliability needs also deter new 

unit installation if pollution control 

systems are less reliable than 

production facilities. On August 19,1988, 

it provided EPA with a "supplement" 

attaching letters attesting to the need for 

high rates of facility reliability. This 

argument does not provide a basis for 

reconsideration under section 307. The 

general point—the need for high steam 

generating unit reliability—was raised 

at the time of proposal and addressed 

during the comment period [See e.g., 

BID, Volume 4 (EPA-450/3-87-024)]. The 

specific argument that this need, like 

increased costs, could deter new 

installation could have been made at 

that time. Factored into the analysis was 

the cost of backup systems generally 

used by industry to ensure steam 

' supply. Use of such backup systems 

should assure reliable operation and 

should not significantly affect 

installation rates. Even if backup 

systems did affect installation rates, the 

point remains that the number of new 

units and replacement units is less 

relevant to standard setting than the -

relationship between control costs and 

emissions. 

CIBO argued that the "new boiler 

survey," properly analyzed, supported 

its claim that EPA overstated emission 

reductions. For reasons explained in 

Section IV below, CIBO's argument does 

not provide information of central 

relevance to the outcome of the rule 

compelling reconsideration under 

section 307. The reasonableness of the 

rule, considering costs, is not 

significantly affected by the total 

number of projected unit installations 

since smaller population projections 

would mean a corresponding reduction 

of control costs. Furthermore, CIBO 

simply renews a contention that was 

raised and discussed during the 

comment period. (See e.g., BID, Volume 

4.) 

CIBO also argued that a post-proposal 

memorandum, which was prepared for 

EPA and discussed the disposal of 

sodium-scrubbing waste, coupled with 

EPA's "reliance" on sodium-scrubbing, 

shows the "impracticability" of the 

rule—or, rather, that the rule renders 

"impracticable" the use of coal-fired 

steam generating units. The postproposal memorandum notes, among 

other things, that several sodium 

scrubbers are located in areas where 

local rules might limit the availability of 

some scrubbing waste disposal options 

(Docket No. A-83-27, Docket Item IV-B12). 

The issue of scrubber waste disposal 

was raised and thoroughly discussed 

both prior to proposal and during the 

comment period. (See e.g., BID, Volume 

4.) CIBO's comments on the postproposal memorandum do not compel 

reconsideration under section 307. The 

possibility that some sources may be 

limited in their disposal options does not 

change the outcome of the rule. 

CIBO also argued that post-proposal 

memoranda prepared for EPA do not 

show that fluidized bed combustion 

(FBC) and lime spray dry scrubbers are 

"demonstrated" technologies. (See e.g., 

Docket No. A-83-27, Docket Items IVB-18 and IV-B-97.) CIBO's critique of 

the post-proposal memoranda does not 

compel reconsideration under section 

307. The Agency's conclusion that FBC 

and lime spray dryers are 

"demonstrated" technologies was 

explained prior to proposal and again in 

response to public comments [See e.g., 

BID, Volume 4; 52 FR 47837; and 

"Summary of Regulatory Analysis" 

(EPA-450/3-86-005).) The EPA's 

conclusion in the final rule, as well as at 

proposal, was based on the judgment 

that test data and other factors indicate 

that high levels of reliability are 

achievable. The post-proposal 

memoranda, while providing additional 

support for this conclusion, were far 

from its sole support. Critiques of the 

memoranda, therefore, are not centrally 

relevant to the finding that these 

technologies are demonstrated for 

purposes of Section 111 of The CAA. 

The merit of CIBO's critiques is 

discussed in Section IV below. 
P.11 

T 

1614 Federal Register / Vnl. 54. No. 9 / Friday, January 13, 1989 / Proposed Rules 

CIBO argued that EPA did not provide 

notice of the "extent" of its reliance on 

vendor guarantees with respect to the 

demonstrated status of lime spray 

dryers and that EPA improperly relied 

on a guarantee that was informal and 

unenforceable. This comment does not 

constitute centrally relevant new 

information compelling reconsideration 

under section 307. As CIBO's comment 

acknowledges, the possibility that EPA 

might refer to vendor guarantees was 

evident during the comment period. (See 

e.g., "Summary of Regulatory 

Analysis.") Moreover, as is discussed in 

Section IV below, EPA's determination 

that lime spray drying.technology is 

demonstrated was based on engineering 

review of lime spray dryer designs, test 

data, and other information that indicate 

that this technology is demonstrated. 

The vendor guarantees were merely 

corroborative of this conclusion. 

CIBO argued that the exemption for 

noncontinental areas from the percent 

reduction requirement should apply to 

all areas where natural gas is 

unavailable. The comment is essentially 

a moot point The noncontinental 

exemption applies in practice only to 

units firing very low sulfur oil. The final 

standard, in fact, exempts all sources 

firing very low sulfur oil from the 

percent reduction requirement, no 

matter where they are located. 

2. Zimmer Owners 

The Zimmer owners argued that 

information provided in their petition 

shows that use of 130 ng SOa/J (0.3Q lb 

SOa/million Btu) oil is not cost effective 

i elative to using a higher sulfur content 

ril. This comment does not compel 

i -^consideration under section 307. The 

original exemption at the time of 

proposal was based on a heat input 

limitation of 86 ng SOa/J (0.20 lb SOa/ 

million Btu), and the exemption in the 

final rule was based on 130 ng SOa/J 

(0.30 Ib/milhon Btu). The Zimmer 

owners' concerns about the cost 

effectiveness of various low sulfur oils 

could have been raised during the 

comment period. The Zimmer owners' 

comment is discussed in more detail in 

Section IV below. 

3. HECO 

The final rule, unlike the proposal, 

exempted oil-fired units in 

noncontinental areas from the percent 

reduction requirement, but limited 

emissions to the equivalent of 130 ng 

SOa/J (0-30 lb. SOa/miUion Btu). HECO 

argued that no notice of the 0.30 

requirement was given, that the 

emissions limit should be raised to 210 

ng SOa/) (0.50 lb SOa/million Btu} on 

Oahu, and that no limit should bn 

imposed elsewhere in Hawaii. 

This argument does not compel 

reconsideration under section 307. It is 

true, as HECO claims, that the emission 

limit of 130 ng SOa/J (0.30 lb SOa/million 

Btu) was developed after (and as a 

result of) the comment period. The 

Agency had. however, established an 86 

ng SOa/J (0.20 lb SOa/million Btu) limit 

as the basis for a percent reduction 

exemption. HECO's objections could 

have been raised during the comment 

period because its objections are based 

on the cost and/or current unavailability 

of very low sulfur oil, i.e., they apply to 

both the proposed emission limit and the 

final emission limit. Further, the 

standard does not require use of 130 ng 

SOi/} (0.30 lb SO,/miUion Btu) oil. but 

rather allows the owner to meet this 

emission limit by whatever means the 

owner chooses. HECO's comments are 

discussed in more detail in Section IV 

below. 

4. API/NFPA 

API and NFPA argued that new postproposal materials and analyses showed 

that various backup strategies for 

maintaining compliance during periods 

of planned and unplanned outages (i.e., 

start-ups, shutdowns, and malfunctions) 

are not available. 

This comment does not compel 

reconsideration under Section 307 

because the information in the API/ 

NFPA petition, including information 

about demand charges and premiums 

for noninterruptible supplies of natural 

gas, was addressed in response to 

comments or could have been presented 

during the public comment period. 

Furthermore, as discussed in Section IV 

below, even upon consideration of the 

information contained in the petition, 

EPA finds no basis for reconsideration 

of the rule. 

II. Petitions Submitted Concerning the 

PM/NO, Standards 

A. Achievability of the PM/NQ, 

Standards 

1. Achievability of NO, Standards by 

Distillate Oil-Fired Electric Utility 

Auxiliary Steam Generating Units 

Petitioner's Comment: The Zimmer. 

owners commented that electric utility 

auxiliary steam generating units that fire 

distillate oil cannot consistently meet 

the NO, standard of 43 ng NO,/} (0.10 lb 

NO,/million Btu] heat input 

Agency Response: Electric utility 

auxiliary steam generating units are 

large field-erected units. These units are 

characterized by low volumetric heat 

release rates, typically below 310400)/. 

sec-m3 (30,000 Btu/hour ft3). Heat 

release rate is one of the major factors 

in determining the NO»-generating 

potential of a unit firing distillate oil und 

the ability of control techniques lo limit 

NO, emisstons. Data show that NO, 

emissions increase as heat release rate 

increases, all other things being equal. 

Emission test data available from three 

distillate oil-fired steam generating units 

employing staged combustion 

demonstrate that NO, emissions can be 

limited to 43 ng NO,/J (0.10 lb NO,/ 

million Btu) or below through the use of 

this technique. (See Docket No. A-79-02, 

Docket Items H-I-224. II-A-9. and II-A14.) One of the units used a staged 

combustion burner while the other units 

used staged combustion air. These 

steam generators are packaged units 

with volumetric heat release rates of 

460,000 to 490.000 J/sec-m3 (45,000 to 

48,000 Btu/hour-ft3), which are higher 

than those typical for electric utility 

auxiliary units. 

Since the heat release rates for 

electric utility auxiliary units are 

substantially below those of the tested 

steam generating units, NO, emissions 

can be limited to 43 ng NO,/) (0.10 lb 

NO,/million Btu) heat input or less 

through the use of staged combustion 

when firing distillate oil. Moreover, 

other NO, limitation techniques, such as 

flue gas recirculation, are available 

which have been shown to be capable of 

limiting NO, emissions to 43 ng NO,/} 

(0.10 lb NO,/million Btu) or less in 

distillate oil-fired steam generating units 

with heat release rates up to 840,000)/ 

sec-m3 (82,000 Btu/hour-ft3). (See 

Docket Na A-79-02, Docket Items U-I224 and IV-B-23.) Accordingly, there is 

no basis for granting the request by the 

Zimmer owners for a higher NO, limit 

2. Special Monitoring Problems 

Associated with Electric Utility 

Auxiliary Steam Generating Units 

Petitioner's Comment- UARG 

contended that the monitoring 

requirements in the NO, standards 

would be difficult, if not impossible, for 

very low capacity factor steam 

generating units to meet. Specifically, 

the petitioner claimed that facilities such 

as oil-fired utility auxiliary steam 

generating units would not be able to 

satisfy the initial performance test 

requirement to be completed within 180 

days of initial start-up because a unit 

that operates only 2 or 3 days per 

month, for example, would take an 

entire year to satisfy these performance 

test requirements.. 

Similarly, tiie petitioner claimed that 

the 30-day rolling average compliance 

test for these same units would not 

produce meaningful data because it is 

unlikely that enough data would be 
T 

P.12 

Federal Register / Vol. 54, No. 9 / Friday, January 13, 1989 / Proposed Rules 1615 

collected in 1 year to calculate even one 

30-day average. 

Agency's Response: The Agency does 

not agree with the petitioner's 

contention that the NO, monitoring 

requirements cannot be met by very low 

capacity factor steam generating units. 

The initial performance test is based on 

emissions data collected during the first 

30 operating days following unit start-up 

(operation of a unit for a single hour 

during a given day qualifies as an 

operating day). Up to 180 calendar days 

can be used to collect these 30 days of 

operating data. Many very low capacity 

factor units may be able to gather 30 

days of data through collection of NO, 

emissions data in conjunction with 

commercial acceptance testing of the 

unit and during normal operating days. 

If insufficient operating days occur 

during the first 180 calendar days, the 

owner can operate the unit and vent 

steam to collect the additional NO, 

emissions data necessary. If collection 

of such data is considered infeasible for 

an individual unit, the owner can apply 

to the Administrator for relief under 

§ 60.8(b) of the General Provisions of 40 

CFR Part 60. 

The petitioner misunderstands the 

mechanics of how 30-day rolling 

averages are calculated in contending 

that insufficient data would be collected 

in a year to calculate 30-day averages. A 

30-day rolling average is calculated as 

the average of all daily average data 

collected during the previous 30 

eonsecutive steam generating unit 

operating days. The first 30-day average 

is calculated after initial unit start-up 

and serves as the initial performance 

test. Thereafter, a new 3t>day rollingaverage is calculated at the end of each 

new steam generating unit operatingday. 

fl. Interrelationship of PM/NO, and SO* 

Standards 

1. Effect of SOi Control Techaiques on 

PM/NO, 

Petitioner's Comment: CIBO stated 

that EPA proposed a stringent (90 

percent reduction) SOt standard after 

proposal of the PM/NO* NSPS. but 

ignored economic and technical 

interrelationships between the proposed 

SOa standards and the promulgated PM/ 

NO, standards. According to the 

petitioner, all of these combustion 

products (PM, NO,, and SO») are 

critically interrelated and. therefore, 

should not have been considered under 

two separate NSPS. The petitioner 

pointed out that implementation of 

control techniques to satisfy the SO* 

standards wiU affect the ceatrol 

techniques necessary to satisfy the PM/ 

NO, standards, both from a technical 

feasibility and a cost standpoint. The 

petitioner also stated that no 

opportunity was given for public 

comment on the technical or cost impact 

of the SOa standards on the PM/NO, 

standards. 

Agency Response: Although NSPS for 

PM/NO, and SOa were developed in 

separate regulatory actions, potential 

technical or economic interrelationships 

were considered throughout the 

development of regulations for each 

pollutant and fuel type. For example, 

because PM and SOa emissions and 

control technologies for oil-fired units 

are closely interrelated, the PM and SOa 

standards for oil were considered in the 

same regulatory action. Relationships 

between the use of a fabric filter or 

electrostatic precipitator (ESP) to reduce 

PM emissions and a flue gas 

desulfurization (FGD) system to reduce 

SOa emissions from coal-fired steam 

generating units were also identified, 

but were found to be separable, and 

were therefore analyzed in separate 

regulatory actions. Possible 

interrelationships between NO, and SOa 

control were also considered, but no 

significant interrelationships were 

identified. 

Further, when evaluating alternative 

SOa standards for coal-fired units, the 

Agency assumed that the proposed PM 

and NO, standards were already in. 

effect and that new units were, 

constructed and operated to comply 

with them. This approach ensured tiiat 

even minor technical and cost 

interrelationships between the 

standards for PM, NO,, and SOY were 

implicitly considered during the course 

of the SO* rulemaking. Accordingly, the 

petitioner's contention that the Agency 

did not consider the interrelationship 

between the PM/NO, and SOt 

standards is incorrect. 

Finally, during the comment period on 

the proposed SOa standards, the public 

could have commented on technical and 

economic interrelationships among the 

PM, NO-,, and SOa standards. However, 

no significant interrelationships were 

identified by any of the commenters. 

Furthermore, mere conjuncture is not a 

basis for granting a petition for 

reconsideration. Only one specific 

interrelationship of the standards was 

identified by the petitioners and, as is 

explained below, it does not impose 

unreasonable impacts. 

2. Achievability of NO, Standards by 

Pulverized Coal-Fired Units When Using 

Backup Fuel to Meet SOa Standards 

Petitioners Comment As a specific 

example to illustrate the PM/NO,/SOa 

interrelationship, CBBO cited a fielderected pulverized coal (PC)-firecl siu'.im 

generating unit firing natural gas or oil 

as a backup fuel. The petitioner stated 

that firing backup fuels in PC units will 

become more frequent and prolonged 

than in the past because of FGD system 

reliability problems, fuel disruptions, 

and fuel price variations. According to 

the petitioner, all PC units are equipped 

with air preheaters, which typically 

deliver preheated air at 110 to 160 "C 

(400 to 600 °F) for combustion of both 

primary and backup fuels. Such high uir 

temperatures, which increase the 

formation of thermal NO,, restrict the 

ability of units with volumetric heat 

release rates below 720,000 J/sec-M3 

(70,000 Btu/hour-ft3) to meet the 43 ng 

NO,/J (0.10 lb NO,/million Btu) heat 

input NSPS for natural gas for distillate 

oil combustion. Since using backup fuel 

is part of the basis for the SOa 

standards, the petitioner stated that this 

requirement must be considered in the 

NO, standards and the necessary relief 

must be provided in the form of a higher 

NO, emission rate for PC units firing 

natural gas or distillate oil with air 

preheat 

Agency Response: Coal-fired steam 

generating anita. inherently have larger 

furnace volumes than oil- and natural 

gas-fired units with equivalent steam 

generating capacities. Because of the 

lower heat release rates in these larger 

furnace- volumes, conversion of 

atmospheric-nitrogen to NO, while firing 

backup fuels in a field-erected PC-fired 

steam generating unit is lower than in a 

smaller, higher heat release rate steam 

generating unit designed to fire natural 

gas or o9. To assure that proper 

combustion conditions are achieved to 

minimize NO, formation, a number of 

NO, reduction techniques are available. 

These techniques include reducing 

combustion ah* temperature by either 

total or partial bypass of the air 

preheater, and using fhie gas 

recirculation, overfire air ports, and low 

NO, burners to fire backup fuels. Data 

from units employing staged combustion 

burner (SCB) or staged combustion air 

technology indicate that these controls 

can meet the 43 ng NO,/} (0.10 lb NO,/ 

million Btu) heat input limit when firing 

natural gas or oil in units with heat 

release rates below 720,000 J/sec-m8 

(70,000 Btu/hour-ft3). In addition, one 

low NO, burner manufacturer stated 

that NO, emissions can be limited to 43 

ng NOJJ (0.10 lb NO,/million Btu) heat 

input white firing natural gas if the unit 

heat release rate is fess than 770.000 J/ 

sec-m» (75.000 Btu/hour-ft3;. (See 

Docket No. A-79-02, Docket Item IV-E14.) 
1616 Federal Register / Vol. 54. No. 9 / Friday. January 13, 1989 / Proposed Rules 

! 

P.13 

Industrial field-erected units have 

heat release rates well below these 

levels. A survey of such units installed 

between 1982 and 1986 identified nine 

PC-fired units. (See Docket No. A-83-27, 

Docket Items IV-J-4, IV-J-5, IV-J-7, and 

IV-J-9, and IV-J-42.) The heat release 

rates for these units ranged from 140,000 

to 245,000 J/sec-m3 (13,500 to 23,700 Btu/ 

hour-ft3). Since these heat release rates 

are substantially below the upper limits 

of 720,000 to 770,000 J/sec-m3 (70,000 to 

75,000 Btu/hour-ft3) identified above, 

NO, emissions can be reduced to 43 ng 

NO,/J (0.10 lb NO,/million Btu) heat 

input or less through use of the above 

NO, reduction techniques when firing 

natural gas or oil as a backup fuel. 

Accordingly, there is no basis for 

granting the CIBO request for a higher 

NO, limit or convening a proceeding to 

reconsider the interrelationship between 

the PM/NO, and SOa standards. 

C. Projected Environmental and 

Economic Impacts 

1. Overstatement of Impacts 

Petitioner's Comment: EPA projected 

that 725 new steam generating units 

with heat input over 29 MW (100 million 

Btu) would be built in the 5-year period 

following proposal. CIBO stated that 

this number is too high (CIBO contended 

that 250 new units are more likely, of 

which 80 percent are replacement units) 

and, as a result the projected economic, 

environmental, and energy impacts 

associated with tha PM/NO, standards 

are overstated. The petitioner cited the 

Agency's own "new boiler survey" to 

support its contention. The petitioner 

contended that the survey shows that 

the number of "new" steam generating 

units as opposed to "replacement" units 

was overestimated, that purchase of 

replacement units is discretionary, and 

that the impact of the standards will be 

to further reduce the number of 

replacement units during the period -

modeled, given the high cost of 

complying with the standards. Thus. 

CIBO argued that the projected emission 

reductions achieved by the standards 

are significantly overestimated. 

Agency's Response: As explained in 

the response to comments in the SOa 

rulemaking (see e.g., 52 FR 47826), 

several factors suggest that 1984 

estimates of steam generating unit 

population and total "new" emissions 

were high. These estimates of new 

steam generating units were based on 

U.S. Department of Energy projections 

made in the late 1970's. (See e.g., BID, 

Volume 4.) As the Agency explained, 

however, any change in the overall 

balance between the costs and benefits 

and, hence the reasonableness of the 

standard, depends on the relative 

change in both costs and benefits. If 

EPA has overestimated the number of 

new units subject to the standard, then 

both the costs as well as the emission 

reductions (i.e., benefits) of the standard 

decrease. EPA's conclusion as to the 

standard would remain valid even if 

CIBO's estimates, or lower ones, proved 

more accurate. 

The total number of new steam 

generating units and the percentage of 

these units that are replacements was 

examined in the "new boiler survey." 

The survey results suggest that about 

half of all unit installations from 1981 to 

1984 represented replacements of 

existing units. However, for four 

reasons, the fact that a significant 

number of new units are replacements 

for existing units does not support 

CIBO's claims that lower-than-projected 

emissions reduction compel 

reconsideration. First, replacement 

capacity may simply displace existing 

capacity in an accounting sense, but it 

represents new capacity under section 

111 of the Clean Air Act Therefore, the 

petitioner's exclusion of replacement 

capacity from its calculations of 

baseline emissions increases is not 

warranted. Second, the suggestion that 

replacement should not be counted 

because it is discretionary and might be 

deferred is unfounded. Deferring 

replacement is simply replacement 

displaced in time to a later date. Third, 

the "new boiler survey" results indicate 

that the decision to install new steam 

generating units is not significantly cost 

sensitive in the range of cost increases 

anticipated by the Agency. Fourth, with 

respect to projected post-NSPS emission 

levels, many of the replaced units are 

not retired but continue in service. 

2. Legal Basis for and Economic Impacts 

of Controls on Electric Utility Auxiliary 

Steam Generating Units 

Petitioner's Comment: In their 

petitions, UARG and the Zimmer 

owners argued that Subpart Db should 

not apply to auxiliary utility steam 

generating units that are used to assist 

in start-up and shutdown of the main 

steam generating unit because these 

units are not significant contributors, 

operate at very low capacity factors, use 

oil or natural gas, operate intermittently, 

and are located in rural areas. The 

petitioners also contended that any 

standards for PM/NO, would result in 

excessive cost impacts on electric utility 

auxiliary steam generating units relative 

to units operated at higher capacity 

factors. According to the petitioners, the 

standards would also have minimal 

impact on reducing PM and NO, 

emissions beyond those achieved by 

current unit designs. Therefore, the 

petitioners recommended that the final 

standards be amended to either (1) 

exempt utility auxiliary steam 

generating units from the standards: (2) 

adopt a capacity factor cut-off for the 

promulgated standards and establish 

different levels of control for units that 

operate at very low annual capacity 

factor levels, such as 10 percent or less; 

or (3) reduce the burden imposed by 

NO, monitoring requirements on steam 

generating units that operate at very low 

annual capacity factors.3 

Agency Response: As the Agencystated in its June 19,1984, proposed rule 

(49 FR 25156), all steam generating units 

with a heat input capacity greater than 

29 MW (100 million Btu/hour) (other 

than those units subject to Subpart Da) 

were included within the Subpart Db 

rule (51 FR 42794). The Agency included 

very low capacity factor units on the 

basis that the design of these units and 

control technologies for emission 

reductions are similar, irrespective of 

capacity factor. As was noted in the 

final rule, "there is no requirement that 

each subcategory of a listed category or 

each individual source within a listed 

category also be a significant 

contributor." (See 51 FR 42795; see also 

51 FR 42772.) It was thereby determined 

that auxiliary utility steam generating 

units are subject to Subpart Db. 

The Agency does not agree that the 

criteria set forth by UARG and the 

Zimmer owners provide a basis for EPA 

to subcategorize utility auxiliary steam 

generating units. No doubt there are 

multiple bases upon which Subpart Db 

steam generating units could be 

subcategorized. Criteria such as 

ownership and/or the existence of 

companion base load units (i.e., units 

owned by utilities, or units auxiliary to 

base load units) do not seem to be 

functionally useful. An exemption for 

rural settings is inconsistent with the 

concept of section 111, which 

contemplates national standards and 

does not distinguish among regions 

based on air quality achieved. Capacity 

factor, although related to the level of 

emissions, is unsuitable as a basis for 

exemption from all standards where 

emission control remains cost effective: 

as the final rule recognizes, however. 

* The Zimmer ownen also contended that section 

111(f) bars EPA from determining that utility 

auxiliary steam generating units are within the 

category of units sub|ect to Subpart Ob and. 

simultaneously, in regulating such units, section 

111(f) requires that EPA establish a list of major 

stationary source categories and establish deadlines 

for regulation. The Zimmer owners do not explain 

their interpretation of section 111(f). On its face, 

section 111(f) contains no such bar. 

I 
P.14 

Federal Register / Vol. 54, No. 9 / Friday, January 13, 1989 / Proposed Rules 1617 

capacity factor is an appropriate 

criterion for exemption where emission 

control is not cost effective. 

As discussed in a separate rulemaking 

notice published today elsewhere in the 

Federal Register, the Administrator, 

under his discretionary authority, is 

proposing to amend the NO, 

performance testing and monitoring 

requirements for steam generating units 

that operate at very low annual capacity 

factors (less than 10 percent) and that 

fire natural gas. distillate oil* or low 

nitrogen residual oil (either alone or in 

combination). The proposed rule 

imposes less burdensome performance 

testing and monitoring requirements on 

large steam generating units and 

exempts small steam generating units 

from the NO, standards. 

The Agency also does not agree that 

auxiliary utility steam generating units 

should be exempted from the 

performance standards for PM and NO, 

on the basis that minimal emission 

reductions will be achieved. Althoughmost auxiliary utility units may be 

designed to fire oils with PM emission 

potentials of less than 43 ng/] (0.10 lb/ 

million Btu) and may be equipped with 

low NO, burners, the performance 

standards provide a "cap** to assure that 

these units are operated in- a manner 

that minimizes emissions- Establishment 

of performance standards as a "cap" ta 

limit future emissions is a valid exercise 

of regulatory authority. . 

D. "New Boiler Survey" 

Consideration of New Information 

Gathered In the "New Boiler Survey." 

Petitioner's Comments: CIBO stated 

that EPA recognised the importance e£ 

steam generating unit replacement when 

it announced that it had initiated a "new 

boiler survey" to gather information 

regarding the impact of the NSPS oa 

new steam generating unit construction, 

and refurbishment (51 FR 16586^ The 

petitioner contended that many new* 

steam generating units ar* replacements 

for existing units and in most cases, 

these new units represent discretionary 

expenditures by unit owners. Aa a 

result, if the cost of a new unit is. too 

high, the owner will continue to use the 

existing unit Because existing units 

frequently have higher emission rates 

than new units, failure to install new 

units will result in higher emission levels 

and fewer reductions than churned by 

the Agency. The petitioner contended 

that EPA should recalculate the net 

reduction in emissions from steam 

generating unit replacement ia its 

analysis and modify the final ride to 

encourage economic replacement of 

higher eajitting. existing units. 

Agency Reponse: Two questions are 

relevant here: First, what is the impact 

of the PM/NO, standards on the rate of 

steam generating unit installations; and 

second, what are the implications of the 

"new boiler survey" for the PM/NO, 

rule. Regarding the first of these 

questions, the "new boiler survey" was 

conducted in response to public 

comments on the proposed SOa 

standards. It focused on collecting data 

about the reasons new units are 

installed, the extent to which new units 

may be replacements for existing units, 

and the impact of new units on overall 

SOa eraisssiorts. The survey did not 

directly examine PM/NO, emissions. 

However, based on the survey data and 

earlier analyses of the cost of PM and 

NO, control techniques, the impact of 

the PM/NOi standards on replacement 

of existing steam generating units is 

considered minimal because of the small 

cost of the PM/NO, standards on new 

units. 

As to the second question* EPA's 

analysis of the "new boiler survey" 

results confirms the need for PM/NO-. 

controls. It may welt be true,, as the 

petitioner contends, that PM and NO, 

emission rates for individual new units: 

will be lower, even absent an. NSPS. 

than for existing units oi equal size and 

fuel use patterns. However, tha level of 

reductions from individual units that 

would occur in the absence of an NSPS 

is less than the emission reductions 

resulting from the promulgated 

standards. 

The argument that NSPS-iaducad 

delays in steam generating unit 

replacement wiB result in higher 

aggregate eraissteoa is net supported by 

analysis. (See Docket A-83-27. Docket 

Item IV-A-4.) Based on unit 

replacement data from the "new boiler 

survey" and thePM and NO, emission 

levels expected from existing andNSPScontroued new steam generating milts, 

aggregate, emissions, from existing and 

new steam generating units al facilities 

covered by the survey wilt increase after 

installation of new units even with the 

NSPS. For PM. the aggregate increase 

was roughly 30 percent retawve- to the 

level occurring prior to new unit 

installation. For NO*, the aggregate 

emissions almost doubled This resntt— 

higher aggregate emission- despite tower 

emission rates, bom mdrvMnal units—is 

caused primarily by emiesion increasesfrom new units installed for new 

applications that substantially exceed 

the emission reductions from faerfttfeswhere replacements occurred Adoption 

of less, stringest emiesioft control 

requirement* for new units would result 

in even greater mcreases fa aggregate 

PM and NO, emissions. As a rusult. 

promulgation of an NSPS with stringtmt 

emission limits is essential if aggregate 

emissions of PM and NO, are to be 

minimized. 

E. IFCAM National Impacts Model 

Validity of the Model 

Petitioner's Comment: CIBO claimed 

that the Industrial Fuel Choice Analysis 

Model (IFCAM) EPA used to forecast 

industrial steam generating unit sales 

has serious shortcomings. The model is 

based on historical data from a period of 

chaotic energy prices and large cost 

differentials between high cost fuels 

(such as natural gas and fuel oil) and 

low cost fuels (such as coal and waste 

fuels). The petitioner stated that the 

previous behavior of steam generating 

unit owners in conserving energy and 

switching fuels would not be repeated 

today because of the large decline of 

natural gas and fuel oil prices relative to 

those for coal and waste fuels. 

According to the petitioner, the IFCAM 

model must be revalidated using the 

steam generating unit sales results 

contained in the "new boiler survey" 

aad energy prices for the period in 

question, allowing for appropriate 

decision lead times. The petitioner 

stated that Ihe IPCAM mode) should not 

be used fei regulatory analyses until this 

revalidation has been accomplished. If 

the IFCAM projections cannot be 

validated tile petitioner stated that they 

must be disregarded and new data 

developed. 

Agency Reponse: The petitioner 

appears to misunderstand the design 

and operation of IFCAM. IFCAM is 

simply a "feast cost" economic choice 

model designed to aid in examining the 

impact of alternate regulatory standards 

on new industrial steam generating 

units. Key economic parameters (such as 

the estimated growth in national 

industrial energy demand and projected 

prices for coal, ott, and natural gas) axe 

inputs to the model and reflect projected 

economic conditions in the future. For 

each alternate regulatory standard 

IFCAM uses the projected fuel prices 

and total industrial energy demand to 

evaluate steam production costs for new 

industrial units spanning a range of 

sizes, capacity factors, and fuels, and 

then selects the steam generating unit 

and fuel combination with the lowest 

after-tax costs over the useful life of 

each unit. The results of these fuel 

choice selections for each new steam 

generating unit are then added together 

to estimate the total costs, emissions, 

and fuel use associated with the 

alternate regulatory standard. 
P.15 

1618 Federal Register / Vol. 54, No. 9 / Friday, January 13, 1989 / Proposed Rules 

Consequently, the impacts of alternate 

regulatory standards are projected by 

IFCAM based on the input values for 

projected fuel prices, projected 

industrial energy demand, and specified 

regulatory requirements. The results 

obtained from IFCAM. therefore, are not 

based on the "past." but are based on 

projections of the "future." 

III. Petitions Submitted Concerning the 

SO: Standards 

A. Legal Basis for Establishing the SOt 

Standards 

1. Consistency of the SOa Standards 

with Congressional Intent 

Petitioner's Comment: CIBO 

supplemented its petition for 

reconsideration with contentions that 

the SOa standard is inconsistent with 

Congressional intent in enacting the 

1977 amendments to the CAA. The 

essence of CIBO's contentions is that 

Congress enacted the section 111 

percent reduction requirement to ensure 

that new sources do not switch to 

natural gas to avoid the application of 

control technology. CIBO contends, 

however, that the percent reduction 

requirement included in the SOa 

standard will encourage new sources to 

switch from coal to natural gas. The 

result, therefore, is to circumvent the 

statute. (The Department of Commerce 

also submitted comments on this point.) 

Agency Reponse: The petitioner's 

contentions that the SOa standard is 

inconsistent with Congressional intent 

are without merit. The petitioner 

misinterprets section 111. Followed to 

. their logical conclusions, these 

contentions mean that the Agency 

should have either not adopted any 

percent reduction requirement at all, or 

adopted a percent reduction 

requirement that applied to all fuels 

(e.g.. coal, oil, natural gas, wood, etc.). 

An SOa standard for fossil fuel-fired 

stationary sources without any percent 

reduction requirement is inconsistent 

with the explicit language of Section 111 

as it was amended by Congress [see 

CAA 111(a), H.R. Rep. No. 95-294 95th 

Cong., 1st Sess. 188 (1977) "Conference 

Report" reprinted in "Legislative History 

of the Clean Air Act Amendments of 

1977", Volume 4, at 2655 "Legislative 

History"]. If the Agency had adopted an 

SOa standard including only a mass 

emission limit, sources could have 

avoided the application of any control 

technology simply by burning oil or low 

sulfur coal. 

An SOa standard with a percent 

reduction requirement applied to all 

fuels, including fuels such as natural 

gas. very low sulfur oil. wood, etc., may 

also be inconsistent with the explicit 

language of section 111, which requires 

the Agency to consider costs. If the 

Agency had adopted an SOa standard 

applying the percent reduction 

requirement to all fuels, unreasonably 

high costs would have been imposed on 

a number of new sources firing fuels 

such as natural gas, very low sulfur oil. 

wood, etc. 

EPA reads the percent reduction 

requirement in section 111 as tempered 

by the requirement that technology be 

the "best technological system of 

continuous emission reduction which 

(taking into consideration the cost 

***)** * has been adequately 

demonstrated." Thus, a percent 

reduction requirement need not be 

applied to certain types or classes of 

sources if the impacts associated with 

imposing this requirement would be 

unreasonable. Consequently, the . 

Agency made a thorough analysis of the 

potential impacts of imposing the 

percent reduction requirement on 

various types and classes of sources. 

Based on this analysis, the Agency 

included exemptions from the percent 

reduction requirement where the 

impacts of imposing this requirement 

would have been unreasonable. The 

final SOa standard, therefore, is 

reasonable and this approach represents 

a reasonable way to harmonize the twin 

requirements of Section 111 to include 

percent reduction requirements and to 

consider costs. 

Finally, even in the absence of tha -

SOa standard, economic factors 

unrelated to the standards, such as the 

relative price between coal, oil, and 

natural gas, are likely to have more 

impact on the choice of fuel for a new 

industrial-commercial-institutional 

steam generating unit than the SOt 

standard. 

2. Impacts of the SOa Standard on the 

Natural Energy Policy 

Petitioner's Comment CIBO claimed 

that the SOa standard is inconsistent 

with national energy policy in that it 

fails to encourage the use of coal, 

threatens a balanced energy supply, and 

reduces the incentive for companies to 

develop clean coal technologies. (The 

Department of Energy and the 

Department of Commerce also 

submitted comments on this point.) 

Agency Response: The petitioner's 

comments are a repetition of comments 

submitted to the Agency during the 

public comment period following 

proposal of the SOa standards. At worst, 

as discussed in the "Summary of 

Regulatory Analysis," the proposal 

notice (51 FR 22384), Volume 4 of the 

Background Information Document and 

the promulgation notice (52 FR 47828). 

the SOa standard will have only a very 

small impact on the overall mix of fuels 

consumed to satisfy national energy 

demands. Thus, the standard will not 

cause a significant change in national 

energy supplies nor will it threaten 

national energy security. 

To illustrate this fact, under the worst 

case scenario examined by the Agency, 

about 600 new coal-, oil- or gas-fired 

industrial-commercial-institutional 

steam generating units are projected to 

be sold over the 5-year period between 

1986 and 1990. These new units will 

result in total fuel consumption of 

roughly 550 PJ/year (520 trillion Btu/ 

year) in 1990. Even if all this energy 

consumption were satisfied by coal, it 

would represent less than 3 percent of 

total United States coal consumption in 

1988. Similarly, if all this energy 

consumption were satisfied by oil or 

natural gas, it would represent less than 

2 percent or 3 percent, respectively, of 

total oil or natural gas consumption in 

1988. 

Not all this increased energy 

consumption in new industrialcommercial-institutional steam 

generating units, of course, will be 

satisfied by a single fuel, such as natural 

gas or oil. Furthermore, the Agency's 

projections of sales of new steam 

generating units are quite likely to be 

overestimated, as the petitioner has 

pointed out Consequently, the impact of 

the SO, standard on changes in the 

national energy mix of coal, oil, and 

natural gas will be even less significant. 

than these figures might indicate. 

The Agency acknowledges that some 

fuel switching to natural gas may occur 

as a result of the SOa standard. As 

discussed in Volume 4 of the 

Background Information Document and 

the promulgation notice (52 FR 47826), 

this fuel switching, however, will be 

small compared to the amount of fuel 

switching that is likely to occur as a 

result of the current low price of natural 

gas. The impact of the SOa standard on 

the difference in cost between firing coal 

or firing natural gas in a new steam 

generating unit is small compared to the 

impact of current natural gas prices. 

Even in the absence of the SOa 

standard, with current low natural gas 

prices few new steam generating units 

are likely to select coal over natural gas. 

Finally, as also discussed in the 

proposal notice (51 FR 22384), Volume 4 

of the Background Information 

Document, and the promulgation notice, 

(52 FR 47826). in developing the SOa 

standard the Agency recognized that the 

standard and. in particular, the 

requirement to achieve a 90 percent 

reduction in SOa emissions, could hinder 
1 

P.16 

Federal Register / Vol. 54, No. 9 / Friday, January 13, 1989 / Proposed Rules 1619 

the development of some new clean coal 

technologies. The potential risk of 

failure that might be associated with 

using a new technology to achieve such 

a high percent reduction requirement 

could be sufficient in some cases to 

deter the use of that technology. Yet it is 

only through new technologies that 

better and less expensive means of 

controlling SOa emissions can be 

developed. 

Although development of new 

technologies should be encouraged, it is 

not reasonable to permit the use of new 

technologies if use of these technologies 

would lead to SOa emissions grossly out 

of balance with what emissions would 

have been if a conventional technology 

had been used. Thus, to encourage the 

development of new technologies that 

show promise of achieving levels of 

performance comparable to those of 

existing technologies, but ensure that 

SOa emissions are not grossly out of 

balance with what they would have 

been if a conventional technology had 

been used, provisions were included in 

the SOa standard that require a 50 

percent reduction in SOa emissions from 

new technologies and limit SOa 

emissions to 260 ng SOa/J (0.6 lb SOa/ 

million Btu). This percent reduction 

requirement is low enough to 

substantially reduce the risk of failure 

associated with achieving it, and the 260 

ng SOa/J (0.6 lb SOa million Btu) 

emission limit ensures that SOt 

emissions from a source using a new 

technology will not be grossly out of 

balance with what SOa emissions would 

have been if a conventional technology 

had been used. 

B. Projected Economic Impacts 

1. Cost Effectiveness of a 130 ng SOa/J 

(0.30 lb SOa/million Btu) Heat Input 

Emission Limit on Electric Utility 

Auxiliary Steam Generating Units at the 

Zimmer Owners' Generating Station 

Petitioner's Comment: The Zimmer 

owners stated that EPA did not consider 

the full costs associated with meeting a 

130 ng SOa/J (0.30 lb SOa/million Btu) 

heat input emission limit for its two very 

low capacity factor auxiliary utility 

steam generating units. The petitioner 

stated that the exemption from the 

percent reduction requirement for oilfired units with a maximum annual heat 

input capacity of 30 percent and less 

was meaningless when their very low 

capacity auxiliary units must also meet 

the 130 ng SOa/J (0.30 lb SOa/million 

Btu) heat input emission limit. 

The petitioner contended that the full 

costs of.meeting a 130 ng SOa/J (0.30 lb 

SOa/million Btu) heat input standard at 

its two auxiliary units are grossly 

disproportionate to the benefits 

achieved [i.e.. Mg (tons) of SOa 

removed). For these units, either very 

low sulfur oil must be burned in both the 

main unit and the auxiliary units or a 

separate oil handling system must be 

installed for the auxiliary units. 

According to the petitioner, the separate 

handling system would cost a total of 

$225,000/year, or $13.000/Mg ($11,800/ 

ton) of SOa removed, whereas burning 

very low sulfur oil in both the main unit 

and auxiliary units would cost a total of 

$190,000/year, or$ll,000/Mg ($10,000/ 

ton) of SOt removed. As a result of these 

unreasonable cost impacts, the 

petitioner recommended that very low 

capacity factor auxiliary units be 

excluded altogether from regulation 

under Subpart Db standards. 

Agency Response: The 130 ng SOa/J 

(0.30 lb SOa/million Btu) heat input 

emission limit for steam generating units 

exempt from the percent reduction 

requirement was established based on 

an assessment of the emissions and 

costs of very low sulfur oils. In 

establishing an NSPS, the Agency 

determines the best technology 

available, considering'costs and other 

factors, for the category of sources 

affected by the standard. This approach 

does not mean that every source 

affected by the standards will incur the 

same costs of compliance. Some 

individual facilities subject to the 

standards may experience higher cost. 

In other words, in setting standards for 

new sources the Agency takes costs into 

account for the category of sources 

considered as a whole, not cost for 

every particular facility that might be 

affected. 

Nevertheless, EPA reexamined the 

cost effectiveness of the promulgated 

SOt standard based on the Zimmer 

owners' specific situation and concluded 

that even in their situation the costs are 

reasonable. 

Of the two compliance alternatives 

identified by the Zimmer owners, the 

lower cost alternative is to use very low 

sulfur oil in both the main steam 

generating unit [which is permitted to 

fire oil with an emission potential of 240 

ng SOa/J (0.55 lb SOa/million Btu)] and 

the auxiliary units, which are subject to 

these standards. Based on the projected 

emission reductions from only the 

auxiliary units [estimated at 17 Mg/year 

(19 tons/year)], the petitioner estimated 

that the cost effectiveness of SOt 

reductions would be $11,000/Mg 

($10,000/ton). However, it is 

inappropriate to exclude the emission 

benefits of using very low sulfur oil in 

the main units. When these emission ' • 

reductions are included, the costeffectiveness level is roughly $3."00/Mu, 

($3,400/ton) of SOa, which is considered 

reasonable. 

Further, these calculations are based 

on a fuel premium that the Zimmer 

owners believe may exist between 130 

and 240 ng SOr/J (0.30 and 0.55 lb SOa/ 

million Btu) oil of six cents per gallon. 

Based on a review of available data on 

fuel sulfur price premiums in the areas 

surrounding the Zimmer station, this 

premium appears overstated. In fact, 

this review identified little, if any, 

premium in the price between 130 and 

240 ng SOa/J (0.30 and 0.55 lb SOa/ 

million Btu) oils. As a result, the actual 

cost-effectiveness level could be 

considerably lower than the value 

calculated above. 

2. Exemption for Noncontinental Areas 

Petitioner's Comment: CIBO 

contended that the exemption of 

industrial steam generating units from 

the 90 percent SOa reduction 

requirement in noncontinental areas 

was arbitrary. According to the 

petitioner, the Agency provided this 

limited exemption due to the 

unavailability of natural gas in 

noncontinental areas. The petitioner 

argued that the distinction between 

facilities in continental and 

noncontinental areas is not supportable, 

considering that steam generating unit 

owners in some areas of the continental 

United States also have difficulties in 

obtaining natural gas. 

Agency Response: The petitioner's 

contention is a moot point. Little or no 

coal is bumed in steam generating units 

loaded in noncontinental areas. Thus, 

the exemption for noncontinental areas 

in the final rule applies in practice only 

to steam generating units burning very 

low sulfur oil. The final standard, 

however, also exempts all steam 

generating units firing very low sulfur oil 

from the percent reduction requirement 

no matter where they are located. In 

effect, therefore, the exemption sought 

by CIBO has already been granted in the 

existing rule. To extend this exemption 

for oil-fired units to coal-fired units in 

the continental United States, would 

present statutory difficulties. Congress 

plainly intended that the Agency utilize 

percentage reduction standards where 

appropriate given other statutory 

constraints, including the obligation to 

consider costs and other environmental 

impacts. 

3. Failure to Analyze Economic Impacts 

on the Paper Industry 

Petitioner's Comment: API/NFPA 

!

 stated that when compared to the seven 

other major steam-using industry groups 
P.17 

1620 Federal RegBter / Vol. 54. No. 3 / Friday, January 13. 1989 / Propoaed Rirfee 

examined ia the "Summary of 

Regulatory Analysis," the paper 

industry ranked first In industrial i 

generating unit fossil fuel consumption. 

However. EPA performed economic 

impact analyses for only six of these 

industries, omitting an analysts of the 

paper industry. According to tiie 

petitioner, such an analysis of the paper 

industry would have revealed important 

information about the impact of the 

standard on the paper industry. 

Agency Response: The CCOHOSMC 

impacts analysis of NSPS for industrial 

steam generating units was conducted in 

two phases. The first-phase focosed on 

major steam-using industries. Usmg 

aggregate economic criteria to 

characterize each industry selected for 

analysis, this phase of the analysis 

examined the potential impact of Mire 

on industry average steam coats and 

product prices, and the ability of the 

industry to pass increased costs forward 

to the consumer or to absorb mcreased 

costs due te high profitability. 

The second phase of the analysis 

focused on selected mrhmtries 

considered likely ts experience dm moss 

severe economic impacts. Industries 

were selected for this phase of the 

analysis based on several cstieria: f» 

Results from the first phase af the 

analysis indicated further analysis was 

appropriate; (2) manufacturing 

operations within an industry were 

considered unusually steam-intensive: 

or (3) the steam generating mat capacity 

within an industry was characterized by 

unusually low utilisation factors. Using 

model plants and model firms 

representative of these fetind within 

each industry selected far analysts, this 

phase of die analysis examined the 

potential impacts af NSPS on product 

prices and profitability at tbe plant lewd 

and capital availability at the fires leweL 

The pah*and paper mdastrywas ane 

of the industries examined tndwnTst 

phase of this analysis. The resume, 

however, indicated that the potential 

impacts of NSPS on this industry were 

small and that further analysis of tins 

industry was sot warranted in tite 

second phase of this analysis. Although 

a stater steam consuming- iadaslry. asset 

of the steam ased HI the pulp and paper 

industry for pulping, blenching, and 

paper matting is generated ayrarraag 

fuels, such as black liquor and wood, 

which are nat subject to the SC% 

standards. Combustion of oil andeeat in 

the pulp and paper industry may 

contribute less than one-third of the 

total steam requirements for this 

industry. There-fete, thepoteitaodhnpact 

af the NSPS an i 

prices is 

In addition, the first phase ef the 

analysis also inrikated thai the pulp and 

paper industry was (pate pasntabte. 

Pulp, paper, and board were produced at 

record leveb m *H**X lsW, and 1988. The 

rates of after-tax profit on stockholders 

equity, tha rates of after-tax profit entotal assets, and the after-tax profits per 

doBar of sales were near or exceeded 

the average for ail mannfketaring plants 

in 1964,1986. and 1988. 

As a result, the pulp and paper 

industry was not considered one of 

those industries hfcely te experience tha 

meat severe economic impacts and. 

therefore, this industry was not 

examiaed in the second phase of the 

analysis. In any case, the petitioner gave 

no indication of how sack an analysts 

would change the outcome of the 

standard. Consequently, the Agency 

finds no basis fior nrontmU-iring the 

standards. 

4. Inadequate Analysis of the Economic 

Impact ef Start-Up, Shutdown, and 

Malfanction Provisions 

Petitioner's Comment: APl/NFPS also 

contended (hat start-up. shutdown, and 

malfunction provisions are needed fior 

the standards because methods of 

compliance with the standards during 

these periods are not always available 

or are too expensive for many new 

paper industry facilities. The petitioner 

contended that EPA had abandoned Its 

earlier position that emissions during 

periods of start-up, shutdown, or 

malfunction would be minimized by 

relying on spare capacity. The petitioner 

added that the Agency now relies en (he 

ability of units to switch to very low 

sulfnr ofl-ornatarai gas during such 

periods. 

Thnperrfroner stated that many paper 

milh eanaet obtain- natural gas and diat 

0.3 weight poiceul sutfui oil-is not 

psueHy available tn many areas ot tne 

ceanary, pantcsfaRy m Honcoostsr 

areas. The petitioner contended that thelack ef nararal gas in Ute noamiiti nentai 

United States was specifically 

recognized in the regulations by 

providing an exemption from me percent 

reduction requirement fer JnciBfles in 

these locations, bat mat the teg-donnas 

flsri-h-maata tar na void season against 

centinotaifa-eia-aastbett 

gator very-haw sutfar fast 

Accc*fdt***-g*» the * 

paper mils with access te natural gas 

would shta meat costs mr eackup 

supplies-of natural gas in «KCSSB of EPA 

assumptions because the gasuusts mat 

were assumed whan <~ 

regnhrthmadidnati 

demand dan-pea and * 

firm gas sapehei, Mirny paaarnana -

would afce incar awcrssiwe cssts fer 

backup supplies of very low sarfur met 

oil. The petitioner estimated that the 

cost effectiveness of SO* removal when 

using nenintemiptabre natural gas or 

very low sulfur oil as a marfunctfon 

backup fuef can be as high as $17,380/ 

Mg (Jl SJHtffoo), a ratio arhnost ten 

times more than estimated "when 

developing the regulations. 

Agency Response: The decision to 

limit SOt emissions during periods of 

start-up. shutdown, and malfunction 

was based on the availability of several 

cost-effective alternatives that an 

affected faculty can use during these 

periods. Contrary to the petitioner's 

assertion, using space FGD- capacity was 

not abandoned as a backup alternative 

and is the most economically attractive 

option in many situations. It is true tbat 

natural gaa is not available everywhere. 

Similasly. very low sulfur residual oil 

may be difficult to obtain in noacoastai 

locations, although very low sulfur 

distillate oil is generally available 

throughout the United States. If neither 

of these fuels is avadabie at a specific 

location, alternatives such as liquid . 

petroleum gas (LPG) or spare FGD 

modules could be considered Each 

alternative need nat be availafe-to at 

every potential location of a new 

facility. 

Taexoats of spans FGD capacity, 

natural gas. and very unraunar oil were 

analyzed prior to prnanhanlan af the 

standards. These cases were reexamined 

based on the eentiaoefs ornaments. En 

adanaoa. use of LPC was also examined. 

Whtra duaand chm-ges cited by the 

petitioner of $8.80 to $11.40/t*nilioo }f 

day/month (37 to $12/millioa Btu/day/ 

month) are assumed for noninterruptible 

natural gas, me coat esnotiveness of this 

option ranges Gram S34W to *11^08/Mg 

($3,500 and $KW0O/tan*. The cost 

eaeca*eaess4-*f aftof tneemer options, 

howeaer, such -a* aatarat gas (which 

does not carry sack aajhrlnmand 

charges), very lew saifureU. LPC. er 

space FGD capacity. reaarins in the 

range of $650 to $*W40aj!Mg ($500 to 

$4400/ion) of SC« remeaed aad is 

considered reasonablar 

Ia adnsmnu most steam osaaj afants 

operateae—MJateasa asaaretiag masts 

at leas man fattcaaechy aa that if <ane 

•mn maanncttena, tbe load can ba 

switched team ana axnt to another. 

Acoasdhnjtodatacattectedin the "new 

lisshs mn si; " ever *M peanut \1m~ 88 

out of 8S)<ef d»<naw«eal- or osi-fired 

units sold between UK and I9M were 

instated at aknte with muHlplu steam 

gunusaSng starts.-Because of #w 

avaaanhvy af aaoKap-ateant generating 

capacity, lauut plants shaaM be abte to 
P.18 

Federal Register / Vol. 54, No. 9 / Friday, January 13, 1989 / Proposed Rules 1621 

shift steam production to another unit 

during periods of FGD malfunction. 

In view of this variety of start-up, 

shutdown, and malfunction compliance 

options, individual plants will be able to 

economically control SOa emissions 

during these periods. 

5. Legal Requirement for Consideration 

of Start-up, Shutdown, and Malfunction 

Costs 

Petitioner's Comment: API/NFPA 

further contended that the courts require 

consideration of start-up, shutdown, and 

malfunction costs, citing National Lime 

Association v. EPA. 627 F.2d 416 (DC 

Circuit 1980) (referred to hereinafter as 

National Lime). According to the 

petitioner, the costs of complying with 

the standards during periods of start-up, 

shutdown, and malfunction are 

unreasonably high and could be avoided 

with a provision for a temporary 

variance during start-up, shutdown, and 

malfunction conditions. 

Agency Response: National Lime does 

not require special start-up, shutdown, 

or malfunction provisions. Rather than 

specifying a particular requirement or 

type of analysis to be undertaken, the 

court in National Lime required only 

that consideration be given to the 

achievability of the standards under the 

anticipated range of operating variables. 

The petitioner correctly pointed out that 

analysis of the achievability of 

standards under the likely range of 

conditions should include an assessment 

of the cost of compliance associated 

with start-up, shutdown, and 

malfunction of FGD equipment. As 

discussed above, the costs of several 

different start-up, shutdown, and 

malfunction alternatives were analyzed. 

The results of this analysis indicate that 

the impacts associated with limiting 

emissions during start-up, shutdown, 

and malfunction are reasonable. Thus, it 

is clear that the Agency's analysis in 

adopting the standards is consistent 

with National Lime. 

6. Availability of 130 ng SOa/J (0.30 lb 

SOa/million Btu) Oil in-Hawaii4 

Petitioner's Comment: HECO stated 

that the unique fuel supply and electric 

* Following the submittal of IU Petition for 

Reconsideration in March, HECO offered to provide 

additional information concerning oil shipments and 

oil consumption on the Hawaiian Islands to support 

its contention that oil containing less than 0.3 

weight percent sulfur was unavailable in Hawaii. 

No such data were forthcoming until December 19. 

1988. some 9 months after submittal of the Petition 

for Reconsideration. The data covered the 1984-

1987 time period, and much of this information 

could have been submitted during the comment 

period following proposal of the rule in lune 1988, 

and certainly the information could have been 

submitted with the Petition for Reconsideration. 

generation situation in Hawaii was not 

considered in establishing the 130 ng 

SOa/J (0.30 lb SOa/million Btu) emission 

limit. HECO contended that EPA should 

broaden the exemption to allow sources 

on Oahu to burn oil with a sulfur content 

of 0.5 weight percent or less, which 

HECO currently is required by local 

regulations to fire on Oahu. 

The two refineries located on the 

island of Oahu purchase crude oils with 

low sulfur contents that, when blended, 

produce low sulfur residual oil with 0.5 

weight percent sulfur or less. These 

refineries cannot supply all of HECO's 

needs, however, and approximately 3 

million barrels of low sulfur residual oil 

are imported by HECO from the West 

Coast of the United States, Singapore, 

and other worldwide sources. 

Meeting a sulfur specification of 0.5 

weight percent permits HECO and the 

two refineries on Oahu to keep costs 

down and allows HECO to purchase low 

sulfur residual oil that is competitive 

with low sulfur residual oil in the 

continental United States. Having to 

purchase low sulfur residual oil with a 

sulfur content of less than 0.3 weight 

percent would increase HECO's costs. 

Besides the premium for this oil, there 

would be additional costs for segregated 

storage, and the benefits would not be 

worth the costs. As a result, the 

promulgated standards would 

effectively preclude new Subpart Db 

steam generating units on Oahu. 

Agency Response: HECO argues, in 

effect, that the exemption from the 90 

percent reduction requirement included 

in the final standard for steam, 

generating units firing very low sulfur oil 

should be increased from 130 ng SO./J 

(0.30 lb SOa/million Btu) to 240 ng SO./J 

(0.50 lb/million Btu) since firing oil 

containing less than 130 ng SO./J (0.30 

lb SOa/million Btu) will increase 

HECO's costs. The mere fact that 

complying with this exemption from the 

percent reduction requirement will itself 

result in some increase in costs, if HECO 

decides to take advantage of the 

exemption, is not a sufficient basis for 

reconsidering the exemption. This 

exemption was not included in the 

standard to provide a convenient means 

for sources to avoid the percent 

reduction requirement or for sources to 

avoid experiencing any increase in costs 

in complying with the standard. 

HECO never advised the Agency that it was having 

difficulty obtaining the data or that It actually 

intended to supplement its petition. The Agency hat 

no obligation to delay action on the Petitions for 

Reconsideration pending submittal, however 

belated, of information from petitioners or other* 

Nevertheless, the responses set forth below do 

address information presented in HECO's December 

19.198a submittal. 

The exemption from the percent 

reduction requirement included in the 

standard for steam generating units 

firing oils of less than 130 ng SOi/J (0.30 

lb SOa/million Btu) was based on a 

broad weighing of the relative costs and 

benefits of percent reduction 

requirements compared to firing oils of 

various sulfur contents. The costs of 

complying with the standard will vary 

somewhat from location to location, and 

at any specific location will depend on 

factors, such as local fuel prices, which 

are unique to that location. Not every 

steam generating unit, therefore, will 

find it advantageous to comply with the 

standard in exactly the same way. Some 

units may find it advantageous to 

comply with the standard by meeting 

the percent reduction requirement, 

others may find it advantageous to 

comply with the standard by firing very 

low sulfur oils. In short, not every steam 

generating unit subject to the standard 

will experience the same costs, nor is 

there any requirement in section 111 of 

the CAA that the Agency tailor the 

standard in such a way that no source 

will experience higher costs than any 

other source. 

In the original rulemaking, the Agency 

examined a broad range of costs 

associated with the standard. (See e.g., 

"Summary of Regulatory Analysis.") 

HECO's contention that it will 

experience increased costs, or for that 

matter even that it may experience 

higher than average costs, in complying 

with the standard (or exemptions from 

the standard) would not have changed 

the outcome of the rule and, therefore, 

does not compel reconsideration. 

Despite this finding, however, the 

Agency is unaware of why any HECO 

facility would be unable to take 

advantage of the exemption from the 

percent reduction requirement for steam 

generating units firing oils of less than 

130 ng SO./J (0.30 lb SOa/million Btu) if 

it chose to, nor does HECO suggest 

otherwise. 

First, Hawaii's access to very low 

sulfur oil may well be equal to or 

superior to that of many areas of the 

continental United States, with its 

access to waterborne shipments of very 

low sulfur fuel oils from Indonesia and 

California, two of the largest markets of 

very low sulfur residual oil in the world. 

Second, available data from the U.S. 

Department of Energy (DOE) for the 

years 1985 and 1988 (Docket No. A-83-

27, Docket Items IV-I-3, IV-I-5, IV-I-8 

and IV-I-7) indicate that about 10 to 20 

percent of the residual oil used by 

HECO in 1985 and 1988 was 0.3 weight 

percent sulfur (or less) with the balance 

being between 0.3 and 0.5 weight 
P.19 

1622 Federal Register / Vol. 54, No. 9 / Friday, January 13, 1989 / Propoaed Rules 

percent sulfur. Additional data indicate 

a significant percentage of the residual 

oil imported into Hawaii (i.e., from 

outside the United States] was less than 

0.3 weight percent sulfur: 7 percent in 

1985:15 percent in 1986: and 85 percent 

in 1987. 

Furthermore, as HECO points out in 

its supplement, it currently imports oil 

from the West Coast of the United 

States and Singapore. Based on review 

of DOE date for 1987 (Docket A-83-27. 

Docket Item VI-B-9), supplies of 

residual eil containing less than 0.3 

weight percent sulfur are currently 

available in California. These residual 

oils are refined from Indonesian and 

Australian crude oils and could be 

shipped to Hawaii. Handling 

requirements for these 0.3 weight 

percent sulfur residual oils are similar to 

those for higher sulfur content residual 

oUs. 

This indicates that residual oil with 

less than 0.3 weight percent siefur is 

available in Hawaii,, has been used by 

HECO in the past, and is available for 

import to Hawaii. 

Third, the possible need for new 

handling facilities does not distinguish 

HECO from other steam generating unit 

owners asd operators. In Hawaii, as 

elsewhere in the United States, 

depending on the type ef oil purchased 

(a matter under me owner or operator's 

control), the ose of very lew sulfsroil 

may require instauanen of dedicated off 

handling and storage facilities •atoagoide 

oi or in place ef, facilities handhng 

higher sulfur content oil. 

Finsay, HBCO claims that the 

increase in costs associated with 

complying with the exemption from the 

percent reduction requirement might 

result in "peaLhscaiaj" the use of new 

steam generating writs an Qahn. HBCO, 

however, does not explain its mtimiiaj 

far this cham. HHCOnmy mean, as it 

suggests with respect to the outer 

islands, that sources may coramut 

diesel rather than staam 

generating units. This decisional far the 

source operator to make. The nesan~anty 

that sources may construct diesel 

engines tamer tiian steam generating 

units is not. however, a basis far 

modifying the standard. 

Fer ail ef thcac reasons, antncreesein 

the sulfur content of need exempted 

fsont the percent redaction requirement 

is not warrsatrd fat Hawaii. 

7. Need for New Oi! Transportation 

System in Hawn-3* 

Petilkmer's Comment HECO also 

stated that, in order far neighboring. 

Islands (hfauLKruiai.Mnlosal. Lunar, 

and Hawaii) loose vesy lewenifa** 

residual faefoiia saw inter-island 

transportation system (including vessels 

and delivery, receiving, and storage 

capacity) would have to be developed. 

Currently, all of the od fired on these 

islands is imported in barges or tankers. 

Steam generating units on the 

neighboring islands fke oil with a sulfur 

content of 2 weight percent or leas, 

which does not require a heated storage 

or distribution system. Importing waxy, 

very low sulfur residual oil would 

require heated barges for inter-island 

transportand a heated storage and 

distribution system on the islands. Coast 

Guard regulations prohibit hearing of 

the barges used for inter-island 

transport, and cons*hnctmg a~heeted 

storage ifiid distribution system weald 

be uneconomical. r-O&Oxanseaded. 

therefore, that the Agency should 

exempt the Hawaiian enter islands from 

the SO* standards aH together or permit 

the use of medium sulfur (2 weight 

percent) oiL 

Agency Response: The nature of the 

lnter-ishn*d transportation system m 

Hawaii does not warrant a special 

exemption for the oater islands. 

Residual oi) capable of meeting an SO» 

emission limit ef 13»flg SO*/J (0.38 lb 

SOk/mdlwn Btu) cetdd be obtained by 

HBCO. as discussed above. Based on 

information received from the Hawaiian 

Department of Energy (Docket No. A83-27, Docket Item VW5-8), theourrent -

method for transporting restduel oil 

between the neighboring islands of 

Hawai » by barge. This same system 

coind be used to transport very tow 

SfffXHT Off *&*R0R£ IfiO fStMMM If 0ll£pv 

modifications 

moeWwatleBs could include deaning 

someof the barges, dedicating them to 

the transport of very row seller an; and 

equipping new steam generating unite 

wfm aew or converted storage -rnocs 

dedicated to the storage of very tow 

sulfur oil. 

Barge transport of ruei on, far from 

being anrque to Hawaii, is pommon 

practice, throughout tfie cuutmentax 

United States. The Coast Guard does 

not prenrort the heating of oarges 

transporting oil; it does have specific 

barge and heating system design 

requirements to ensure that od is safely 

shipped (Docket A-83-27. Docket Rem 

IV-B-Hfc 

Depending on the type of od 

purchased, a matter entirely mister 

HECO's control use of very lew saner 

residue! eil amy reenirs oon8*n*a*ctiOR of 

a heated storage ami disU-ruutton 

system.TJkeneedfJar this type af sysavn. 

however, would be aetKMaraBtiare 

now steam generating taut located in 

Ha watt tiian for a similar unit located ia 

the continental United States. '< 

Therefore, an exemption from the 

standard for steam generating units 

located on the outer islands or an 

increase from 130 ng SOi/J (0.30 lb SO,/ 

million Btu) to 867 ng SO»/J (2.0 lb SOa/ 

million Btu) in the sulfur content of the 

oil exempted from the percent reduction 

requirement for the outer islands based 

on the need to make changes to the 

existing inter-island transport system or 

the cost of constructing a heated storage 

and distribution system is unwarranted. 

8. Increased Use of Large Steam 

Generating Units or Gas Turbine 

Generators in Hawaii 

Petitioner's Comment HECO former 

stated that if it is required to comply 

with tha 130 ng SOj/J (0.30 lb SO,/ 

mdlion Btu) SO, limitation, it would 

install gas turbine generators or electric 

utility steam generating units witii heat 

inputs greater than 73 MW (250 million 

Bru/hour) rather than Subpart Db units. 

According to the petitioner, such large 

utility steam generating units and gas 

turbine generators could comply with 

Subparts Da or GG by using the 0.5 

weight percent sulfur residual oil 

a vadaUe on Oeha. 

Agency Response; Subpart Db appnes 

to steam generating units with a heat 

input capacity greater tiian 29 MW (108 

mitneit Btu/hour), except for electric 

utility steam generating units covered by 

Subpart De. Indeed, the petitioner could 

install electric utility steam generating 

units m excess of 73 MW (250 miftron 

Btu/hour) heat input or a gas turbine 

generator and be subject to Subpart Da 

or GG, respectituly. rather man Subpart 

Db. Large electric utility steam. 

generating unite or gas turbine 

geneiaters can comply with the SO, 

requirements or Subparts Da or GG by 

firing 6-6 weight percent suffur oil. 

9. Economic Impacts of Firing Low 

Sulfur Oil fart the Hawaiian Outer Islands 

Petitioner** Comment HECO noted 

that the cost differential between 

disuhateed and residual oil makes the 

use of distiflaW oil in staam generating 

units impracticable on the outer islands 

compared to diesel engines. The result, 

according to HECO, is that no one will 

build steam generating units: father, 

they m l burn distillate ed in more 

efficient diesel engines. 

Agency AeajMaso* TheSO* staadnrds 

merely iian^ the aanar content of oti tiiat 

may be fired withoirt meeting the 90 

percent reduction requirement The 

standards do net require aew steam 

genesaaaguaits taking advantage of (his 

exemption te ibe cBstrnate on. but 

permit new steam generating units to 

fire a*ar4«e-<rfeiLTJu*M»sro alight 
.1 

P.20 

r~ 

• 

Federal Register / Vol. 54, No. 9 / Friday, January 13, 1989 / Proposed Rules 1623 

find it more economical to make use of 

diesel engines to produce electricity 

does not make the standard 

unreasonable. As stated earlier, the 

Agency believes that residual oil 

containing less than 130 ng SOi/J (0.30 

lb S02/million Btu) is available and can 

be supplied to steam generating units in 

Hawaii. HECO, however, always has 

the option of using distillate oil. residual 

oil, or even crude oil, or of switching 

between these fuels, based on its own 

assessment of fuel costs, supply 

uncertainties, and other factors. 

Furthermore, if transportation costs or 

use of very low sulfur content oil in the 

Hawaiian Islands becomes too 

expensive, HECO may wish to consider 

partial scrubbing of higher sulfur content 

oil to achieve the 130 ng/J (0.30 Ib/SO, 

million Btu) emission limit. 

fl. Post-Proposal Developments 

1. New Docket Material 

Petitioner's Comment- CIBO 

contended that EPA introduced new 

material into the docket and conducted 

new analyses of existing data after the 

close of the public comment period, and 

that the public was not given sufficient 

opportunity to comment on this new 

material. 

Agency Response: In the proposed 

SO, rulemaking of June 19,1986. EPA 

stated that the energy price scenarios 

would be updated between proposal 

and promulgation to determine whether 

the costs, emission reductions, or cost 

effectiveness of the rule would be 

altered significantly, and. when 

completed, this information would be 

added to the docket. (See 51 FR 22387.) 

On April 27,1987. and again on 

October 30,1987, a notice of document 

availability was sent to parties who 

commented on tbe June 19,1986. 

proposed rulemaking, informing them 

that new materials and analyses were 

being added to the docket. These notices 

included a listing of more than two 

dozen new reports related to the 

rulemaking, which can be found in 

Docket No. A-83-27. Copies of four of 

the reports, including the results of the 

"new boiler survey," were attached to 

the April notice and six were attached 

to the October notice. 

None of the petitioners commented on 

these new materials nor did they submit 

any additional information. Further, die 

new analyses showed no significant 

differences from the analyses that led to 

the development of the proposed 

standard and reaffirmed the 

reasonableness of the final standard. 

2. Analysis of the "New Boiler Survey" 

Petitioner's Comment: CIBO objected 

to a question in the "new boiler survey" 

which asked, "Would your decision to 

build a new boiler change if projected 

costs to produce steam increased by: 10, 

20, 30, or 50 percent?" The petitioner 

contended that this question was 

misleading because it failed to reveal 

the source of the increased cost of 

meeting the 90 percent SO, emission 

reduction requirement. The petitioner 

also contended that the question failed 

to address costs, other than incremental 

steam cost, that would affect project 

viability. The petitioner suggested that 

the question be rephrased to ask, 

"Would your decision to install a coalor oil-fired boiler change if such boiler 

were subject to a requirement (1) that 90 

percent of potential SO, emissions be 

removed on a continuous 30-day 

average basis (including start-up and 

shutdown periods), and (2) that the 

installation of low sulfur fuel-firing 

capability might need to be installed for 

periods of FGD system malfunction?" 

Agency Response: The purpose of the 

"new boiler survey" was to determine to 

what extent new steam generating units 

may be replacements for existing units 

and what impact this may have on 

overall SO* emissions. Thus, the survey 

focused on the reasons motivating the 

installation of new units, the disposition 

of existing units that may be replaced by 

new units, and the overall impact of the 

installation of new unite on SOfe 

emissions. The specific question on 

costs was included in the survey to 

gauge how sensitive decisions to install 

new units, including those units that 

may replace existing units, may be to 

potential increases in costs. The 

petitioner hypothesized that the answers 

might have been different if EPA had 

formulated its question to specify that 

increased costs resulted from pollution 

control. In determining the cost of 

steam, prudent business practices would 

be to include all the costs associated 

with steam production, including any 

costs associated with pollution control 

and steam supply reliability. It is the 

majpntude, not the origin, of costs that is 

relevant to the elasticity of sales as a 

function of costs. No details or data 

were provided to support CIBO's 

conjecture. Unsupported conjecture n 

not an adequate basis for reconsidering 

a rule. 

3. Reevaluation of SO, Emission 

Reductions 

Petitioner's Comment CIBO also 

contended that EPA faded to reevaraate 

SO, emission reductions in light of the 

data received from tiie "new boiler 

survey" conducted after proposal of the 

standards. Specifically, the petitioner 

contended that the SO2 emission rates 

used by EPA were too high and, as a 

result, SO, emission reductions were 

overestimated. The petitioner also 

contended that the overall emission rate 

gleaned from the survey demonstrates 

that a 1,100 ng SO,/J (2.5 lb SOi/million 

Btu) heat input baseline for new coalfired steam generating units is 

unjustifiably high. The petitioner also 

contended that the survey demonstrates 

that SOa emission rates for oil-fired 

units were overestimated. The petitioner 

stated that without an accurate estimate 

of emission reduction, EPA cannot fulfill 

its statutory obligation under the CAA 

to accurately determine the cost of 

achieving the emission reductions that 

any particular standard will impose. 

Agency Response: The Agency did 

analyze the impacts of the SO, 

standards using SO, emission rates from 

the "new boiler survey." In fact, for 

every analysis of national impacts 

performed by EPA, both prior to and 

after proposal of the standards, the 

Agency included regulatory alternatives 

that were essentially the same as dM 

emission rate indicated by the survey to 

represent baseline levels. Because the 

Agency analyzes the incremental 

impacts oi each regulatory alternative 

over the next less stringent alternative, 

the designation of a particular emission 

level aa "baseline" rather than a 

"regulatory alternative" has littie 

practice effect The incremental 

differences wnl be the same in either 

case. 

Each of the Agency's analyses 

included emission levels lower titan 

1,100 ng SOt/J (2.3 B> Sft/milhen Btu) 

for coal-fired units and 1.300 ng SO,/J 

(ao lb SOk/million Btu) for oil-fired 

units. For example, each analysis 

included an alternative based on an 

emission level of 620 ng SO, /J (li lb 

SOi/milhon Btu) and 340 ng SO, f] (0.8 lb 

SOi/nrilnon Btu) for coat- and oil-fired 

units, respectively. These emission 

levels are essentially the same as those 

the petitioner believes can be gleaned 

from the survey as representative of 

baseline emission tevels. 

In each analysis, the impacts of the 

regulatory alternative eventually 

promulgated as the SO, standards were 

analysed relative to toss stringent 

alternatives, including an emission level 

essentially comparable fo the "revised 

baseline" level proposed by the 

petitioner. In each instance, the impacts 

of the promulgated standards were 

reasonable coatpared to this "revised 

baseline** level. Consequently, the 

Agency did analyze the impacts of the 
P.21 

1624 Federal Register / Vol. 54, No. 9 / Friday, January 13, 1989 / Proposed Rules 

standards in light of the results of the 

survey and found those impacts to be 

reasonable. 

4. Information on Impacts of Waste 

Disposal 

Petitioner's Comment: CIBO argued 

that post-proposal information showed 

that significant waste disposal problems 

would be created by the SO, standards. 

It also argued that methods used in 

some areas for disposing of sodium 

scrubber waste (i.e., deep well injection, 

use of lined disposal sites) are not cost 

effective, making the use of coal-fired 

steam generating units impracticable. 

Agency Response: Steam generating 

units generally do not operate in 

isolation from other industrial 

processes, but are most often part of a 

larger industrial manufacturing plant 

that itself often produces substantial 

quantities of wastes requiring disposal. 

In addition, coal-fired steam generating 

units generate fly ash as well as liquid 

feedwater and steam system "blowdown" wastes, which also require 

disposal. Thus, use of SO, control 

systems to reduce SO* emissions from 

steam generating units may increase the 

volume of wastes to be disposed of, but 

generally does not create a new problem 

(i.e., a need to dispose of wastes where 

no such need existed before). 

In areas where disposal of waste 

streams from sodium FGD or any other 

FGD system is considered by the owner 

or operator of a new steam generating 

unit covered by the NSPS to be too 

costly, the owner or operator could 

select an alternative approach to comply 

with the NSPS. As discussed throughout 

volume 4 of the "Background 

Information Document," the "SO, 

Control Technology Updates Report," 

and the "Summary of Regulatory 

Analysis," the SO, standards are based 

on a wide variety of techniques for 

controlling or reducing SO* emissions. 

The types of waste produced by FGD 

systems are quite different. As a result 

a steam generating unit owner can 

select the FGD system best suited to 

local waste disposal requirements. 

Sodium FGD systems, for example, 

produce a liquid waste requiring 

disposal. Lime spray drying systems and 

FBC systems, on the other hand, 

produce a dry waste product. The cost 

impacts associated with each of these 

SOj control technologies, including the 

costs of waste disposal, are considered 

reasonable. Thus, one can minimize 

problems associated with increased 

waste disposal by appropriate selection 

of the SO, control system. The NSPS 

does not create an insurmountable 

waste disposal problem nor does it 

make the use of coal-fired steam 

generating units impractical. Finally, 

even though not a basis of the standard, 

if the steam generating unit owner or 

operator views the cost of these control 

techniques as excessive, switching to an 

alternate fuel, such as natural gas or 

very low sulfur oil, which imposes no 

additional waste disposal requirements, 

is an option. 

5. Ability of FBC and FGD Systems to 

Achieve 90 Percent SO, Reduction 

Petitioner's Comment: CIBO 

questioned the ability of FBC units to 

achieve 90 percent SO, reduction, 

especially those units experiencing large 

load swings. In addition, the petitioner 

stated that new information on spray 

dryer FGD systems does not support the 

ability of this technology to meet the 90 

percent SO, reduction requirements. The 

petitioner claimed that EPA relied on 

switching to natural gas, and that such 

reliance violated EPA's duty to 

promulgate a standard that is 

achievable for coal- and oil-fired units. 

Agency Response: As discussed in 

Volume 4 of the "Background 

Information Document," sufficient shortterm performance test data exist to 

demonstrate that FBC technology is 

capable of achieving 90 percent SO, 

removal. Short-term data presented in 

the "Summary of Regulatory Analysis" 

show that several FBC units achieved 90 

percent or greater SOa control during the 

test periods. Longer term data (30 days 

or more) also demonstrate that FBC 

units care capable of achieving greater 

than 90 percent SOt removal at high 

reliability levels. A 30-day test on a 

bubbling bed FBC unit burning high . 

sulfur coal showed SO, removal 

efficiencies averaging 93.5 percent. A 30-

day test conducted at another site 

showed an average SO, removal of 90 

percent with greater than 99 percent 

reliability. During a 67-day period at this 

site, the FBC unit had a reliability of 97 

percent. In addition, vendors have 

consistently stated that FBC units can 

be designed to achieve 90 percent SO, 

removal at high reliability levels. Based 

on these data, EPA believes that FBC 

has demonstrated the ability to meet the 

90 percent SO* reduction requirement in 

the promulgated standards. 

In response to the petitioner's 

comment regarding the ability of FBC 

units to respond to load swings, FBC 

technology is characterized by the large 

thermal mass of the bed, which in turn 

limits the ability of FBC units to adjust 

quickly to large variations in steam 

demand. This is a characteristic of FBC 

technology that is unrelated to SO, 

removal. As a result the owner of a 

facility with rapidly changing steam 

demands is likely to select a 

conventional steam generating unit and 

FGD system, rather than an FBC, due to 

this inherent characteristic of FBC 

technology, which limits its ability to 

respond to large load swings. 

The percent reduction and reliability 

of lime spray drying have also been 

demonstrated, as discussed in Volume 4 

of the "Background Information 

Document" and as documented in the 

"Summary of Regulatory Analysis" and 

the "SO, Control Technology Update 

Report." Although few long-term (30 day 

and longer) data are available to 

demonstrate high SO, removal levels, 

short-term tests indicate that lime spray 

drying systems are capable of achieving 

percent reduction levels in excess of 90 

percent. Although most lime spray 

dryers today are operated at roughly 70 

percent reduction to comply with the 

lower percent reduction requirements in 

Subpart Da and in State permits, there is 

no reason to believe lime spray dryers 

cannot achieve 90 percent SO, reduction 

while maintaining a high degree of 

reliability. In fact, those periods during 

which high removal levels have been 

achieved in percent reduction tests 

indicate that lime spray drying systems 

are capable of achieving high percent 

reduction levels with high reliability 

levels. In addition, as with FBC 

technology, a vendor has also stated 

that lime spray dryer FGD systems can 

be designed to achieve 90 percent SO, 

removal at high reliability levels (Docket 

No. A-83-27. Docket Item VI-D-5). For 

these reasons, EPA believes that lime 

spray drying has demonstrated the 

ability to meet the 90 percent SO, 

reduction requirement in the 

promulgated standards. (See 52 FR 

47837.) 

In this connection, EPA stated in the 

promulgation preamble that one 

vendor's guarantee that 95 percent 

reliability was achievable in industrial 

applications was "consistent" with the 

results of 2 years operation of a lime 

spray drying system on a 132 MW (450 

million Btu/hour) heat input coal-fired 

steam generating unit. (See 52 FR 47837; 

see also Docket A-83-27, Docket Item 

IV-B-9.) This statement remains true. 

The distinctions noted by the petitioner 

between this application and industrial 

applications regarding removal rates 

and load levels do not invalidate the 

comparison. The lower removal rate 

does not mean that EPA is incorrect in 

judging that higher removal rates can be 

achieved in industrial applications. 

Likewise, differences in loads do not 

mean that EPA's judgment is mistaken 

that load changes can be managed. The 

Agency's use of the comparison was 

fair. The example was not used as direct 

I 
{k •'*••» v 

P.22 

Federal Register / Vol. 54. No. 9 / Friday, January 13. 1989 / Proposed Rules 1623 

and 

e to 

o 

lity 

*ne 4 

ie 

and 

e 

'day 

•ray 

ving 

:90 

•70 

ts in 

re is 

•rs 

.tion 

"8 

ms 

it . 

proof of reliability. It served as a useful, 

but not necessary, illustration that the 

vendor guarantee in question was 

realistic. Moreover, the Administrator's 

determination that the standard was 

reasonable was not based on the 

assumption that fuel switching would 

occur. 

6. Use of Vendor Statements to Support 

90 Percent SQ> Reduction 

Petitioner's Comment: CIBO stated 

that informal vendor statements had 

been used to support that assertion that 

lime spray dryers can achieve a 90 

percent SQ. reduction. The petitioner 

asserted that a vendor guarantee does 

not reflect "adequately demonstrated" 

performance because the standard 

"must be based on cost-effective 

technologies that can be successfully 

and reliably used in operating 

installations." The petitioner also stated 

that EPA did not provide notice of how 

much EPA relied on vendor guarantees 

in finding that lime spray dryers are 

"demonstrated." 

Agency Response: Data, analysis, and 

engineering judgment were used to 

establish the 90 percent SOi reduction 

standard. The vendor guarantee was 

used merely to confirm the regulatory 

decision and not as the sole basis for the 

standard. The term "adequately 

demonstrated" does not mean 

"successfully and reliably used in 

operating installations." An 

"achievable" standard need not be 

already routinely achieved in the 

industry. [See National Lime 

Association v. EPA, 627 F.2d 416 (1980); 

Sierra Club v. Costle, 657 F.2d 298 

(1981); and Portland Cement Assn. v. 

Ruckelshaus. 486 F.2d 375 (1973).) 

Rather, to be achievable, the standard 

must be achievable under most adverse 

conditions that can reasonably be 

expected to occur. (See National Lime, 

supra.) 

The vendor in question is a leading 

spray dryer FGD manufacturer, having 

installed over 50 percent of the existing 

units, and is a reliable and authoritative 

source of information on dry FGD 

systems. The vendor's statements were 

only used to support the data and 

engineering judgment that served as the 

basis of the standards. CIBO's criticisms 

of such guarantees are not "centrally 

relevant" to the outcome of rule. In fact, 

EPA's determination that the lime spray 

technology was "demonstrated" was 

based, in the proposal as in the I'inul 

rule, on the data in the record und its 

judgment that high levels of 

performance and reliability were 

achievable. The Agency noted the 

availability of performance guarantees 

at the time of proposal only as 

additional support for, but not the basis 

of. its position. (See e.g., BID, Volume 4.) 

IV. Summary 

The issues raised in each petition and 

discussed in this notice were carefully 

considei°d; however, only the issue 

concerning cost impacts of the NO, 

standard on very low capacity factor 

steam generating units provides a basis 

for revising the promulgated standards. 

A proposal to do so will be made in a 

separate notice. The other issues raised 

by petitioners do not require or justify 

reconsideration of the promulgated PM, 

SO,, or NO, standards under Section 

307. 

Date: January 6,1989. 

Lee M. Thomas, 

Administrator. 

(FR Doc. 89-701 Filed 1-12-89; 8:45 am| 

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