United States
Environmental Protection
Agency
Office of Air Quality
Planning and Standards
Research Triangle Park NC 27711
EPA-450/3-82-023b
September 1985
Air
SO2 Emissions in
Natural Gas
Production
ndustry—
Background
Standards
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EPA-450/3-82-023b
SO2 Emissions in Natural Gas Production
Industry—Background Information for
Promulgated Standards
Emission Standards and Engineering Division
U.S. ENVIRONMENTAL PROTECTION AGENCY
Office of Air and Radiation
Office of Air Quality Planning and Standards
Research Triangle Park, NC 2771 1
September 1985
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This report has been reviewed by the Emission Standards and Engineering Division of the Office of Air
Quality Planning and Standards, EPA, and approved for publication. Mention of trade names or commercial
products is not intended to constitute endorsement or recommendation for use. Copies of this report are
available through the Library Services Office (MD-35), U.S. Environmental Protection Agency, Research
Triangle Park, North Carolina 27711; or, for a fee, from the National Technical Information Services, 5285
Port Royal Road, Springfield, Virginia 221 61.
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ENVIRONMENTAL PROTECTION AGENCY
Background Information
and Final Environmental Impact Statement
for Sulfur Dioxide Emissions from
Onshore Natural Gas Processing Plants
Jaa* R. Farmer • ^ ' '
Director, Emission Standards and Engineering Division
U. S. Environmental Protection Agency
Research Triangle Park, North Carolina 27711
1. The promulgated standards of performance will limit emissions of
sulfur dioxide from new, modified, and reconstructed sweetening and
sulfur recovery units. Section 111 of the Clean Air Act (42 U.S.C
7411), as amended, directs the Administrator to establish standards
of performance for any category of new stationary source of air
pollution that "... causes of contributes significantly to air
pollution which may reasonably be anticipated to endanger public
health or welfare."
2. Copies of this document have been sent to the following Federal
Departments: Labor, Health and Human Services, Defense,
Transportation, Agriculture, Commerce, Interior, and Energy; the
National Science Foundation; the Council on Environmental Quality;
State and Territorial Pollution Program Administrators; EPA
Regional Administrators; Local Air Pollution Control Officials;
Office of Management and Budget; and other interested parties.
3. For additional information contact:
. Mr. David W. Markwordt
Chemicals and Petroleum Branch (MD-13)
U.S. Environmental Protection Agency
Research Triangle Park, N.C. 27711
Telephone: (919) 541-5671
4. Copies of this document may be obtained from:
U.S. EPA Library (MD-35)
Research Triangle Park, N.C. 27711
Telephone: (919) 541-2777
National Technical Information Service
5285 Port Royal Road
Springfield, VA 22161
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TABLE OF CONTENTS
TITLE PAGE i
DISCLAIMER ii
TABLE OF CONTENTS iii
LIST OF TABLES v
1.0 SUMMARY 1-1
1.1 Summary of Changes Since Proposal 1-4
1.2 Summary of Impacts of Promulgated Action 1-4
1.2.1 Alternatives to the Promulgated Action 1-4
1.2.2 Environmental Impacts of the Promulgated
Action 1-4
1.2.3 Energy and Economic Impacts of the
Promulgated Action 1-4
1.2.4 Other Considerations 1-4
1.2.4.1 Irreversible and Irretrievable
Commitment of Resources 1-4
1.2.4.2 Environmental and Energy Impacts
of Delayed Standards 1-5
2.0 SUMMARY OF PUBLIC COMMENTS 2-1
2.1 Need for Standards 2-1
2.2 Applicability of the Standard 2-12
2.3 Definitions 2-18
2.4 Emission Control Technology 2-23
2.5 Selection of Model Plants 2-33
(continued)
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TABLE OF CONTENTS (Concluded)
Page
2.6 Economic Impact Analysis 2-35
2.7 Cost-Effectiveness Analysis 2-45
2.8 Small Plant Exemption 2-55
2.9 Catalyst Life 2-63
2.10 1000°F Temperature Requirement 2-65
2.11 Format of the Standard 2-68
2.12 Monitoring and Performance Test Requirements 2-71
2.13 Recordkeeping and Reporting Requirements . . 2-87
2.14 Difference in State and NSPS Requirements 2-91
2.15 Miscellaneous Comments 2-95
APPENDIX A A-l
IV
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LIST OF TABLES
Table Page
2-1 List of Commenters on Proposed Standards for
Onshore Natural Gas Processing: S02 Emissions 2-2
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1.0 SUMMARY
On January 20, 1984, the Environmental Protection Agency (EPA)
proposed standards of performance for the onshore natural gas processing
industry (49 FR 2656) under authority of Section 111 of the Clean Air Act.
The standards limit atmospheric emissions of sulfur dioxide (S02) from
onshore natural gas processing facilities. Public comments were requested
on the proposal in the Federal Register. There were 36 commenters
composed of industry trade association representatives, industry
representatives, plant personnel, and State regulatory agencies. Also
included was one process engineering design firm. The public comments
along with responses to these comments are summarized in this document.
The comments and responses serve as the basis for the revisions made to
the standard between proposal and promulgation.
1.1 SUMMARY OF CHANGES SINCE PROPOSAL
In response to the public comments and as a result of reevaluation,
certain changes have been made in the proposed standards. The emission
reduction efficiency requirement format of the standard has not changed.
Control of S02 emissions is based on sulfur recovery efficiencies
achievable with the technologies selected as representative of best
demonstrated technology. The equations used in the calculation of
required recovery efficiencies remain the same.
The following are changes made to the standards since proposal:
(1) The proposed 1.0 LT/D cutoff has been changed to a cutoff of
2.0 LT/D. The proposed 1.0 LT/D cutoff was based on an analysis of the
incremental cost effectiveness of the technology included in the
regulatory alternative on which the standards were based compared to the
baseline alternative. This analysis assumed an average capacity
utilization of the affected facilities of 100 percent. Based on data
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received from commenters, the Agency has determined that average capacity
utilization is typically closer to 75 percent. Incorporation of the
75 percent capacity utilization assumption into a revised cost-
effectiveness analysis resulted in the 2.0 LT/D cutoff that is being
promulgated.
(2) The costs per ton of emission reduction are higher for plants
with low H2S concentrations in the acid gas (relative to the facility's
sulfur feed rate) than they are for plants with higher, more typical H2S
concentrations. To ensure that the cost effectiveness of controls at
these facilities is similar to the cost effectiveness of controls at the
other facilities covered by the standards, the standards have been
revised to require less stringent emission reduction efficiencies for
these plants.
(3) The proposed standards required determinations of achieved
emission reduction efficiency over every 12-hour period. These 12-hour
average efficiencies were then compared to a required efficiency (Z)
determined quarterly. Several commenters, citing potential variability
in sulfur feed rates over time, indicated that a requirement based on a
determination made up to 3 months in the past may not remain achievable.
To eliminate this problem, the standards have been changed to require
daily determinations of required efficiency (Z). The standards also
have been changed to require the determinations of achieved emission
reduction efficiency over each 24-hour period instead of each 12-hour
period. This change does not significantly diminish the accuracy of the
determination but responds to comments indicating that some small remote
plants may be unmanned for up to 12 hours each day.
(4) Based on an incremental cost-effectiveness analysis, monitoring
requirements for facilities with design capacities less than 150 LT/D
have been changed to allow less rigorous monitoring methods. Instead of
continuously monitoring stack gas S02 concentrations, these facilities
may calculate emission reduction efficiency on a daily basis based on
measurements of inlet sulfur and recovered sulfur once every 24 hours.
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(5) The requirement for maintaining the incinerator combustion
zone temperature at 1000°F has been deleted. Instead, a site-specific
temperature requirement, determined during the performance test, will be
required for those facilities with stack monitors. This temperature
must be sufficient to ensure that at least 98 percent of the sulfur in
the stack gas will be in the form of S02. The standard also now allows
plants the flexibility of monitoring both S02 and total reduced sulfur
compounds in lieu of meeting the minimum temperature requirement.
In response to comments on the proposed standards pertaining to the
economic impact analysis, a revised analysis was conducted using a
different methodology and incorporating several updated assumptions.
The new analysis used a discounted cash flow model (calculating the net
present value of each model case over the timeframe of the analysis).
Updated assumptions included: a variable price for gas (instead of the
constant $4.80 per thousand cubic feet (MCF) used in the original
analysis) ranging from $3.88/MCF in 1985 to $5.82/MCF in 1994; a 12-year
plant life for facilities with sulfur feed rates <20 LT/D instead of a
20-year life; and a $77/LT value for sulfur credits for plants with
sulfur feed rates >5 LT/D rather than the 1100/LT value assumed in the
previous analysis. Baseline sweetening costs were included in the new
analysis. Of approximately 1,000 cases analyzed (different combinations
of sulfur feed rate, H2S-to-C02 ratios in the acid gas, and H2S content
in the sour gas), 27 could, if built, experience adverse economic impacts
due to the NSPS. However, the cumulative probability of facilities with
these particular combinations of gas characteristics being built in the
future is only about 1 percent. Given this low probability, the
conclusion of the revised analysis is that there will be no adverse
impacts on plants likely to be built in the future. Thus, the standards
are not expected to adversely affect incentives to develop new sour gas
fields, and they are not expected to result in an increase in the price
of natural gas.
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1.2 SUMMARY OF IMPACTS OF PROMULGATED ACTION
1.2.1 Alternatives to the Promulgated Action
The regulatory alternatives are discussed in Chapter 6 of the
background information document for the proposed standards (EPA-450/3-
82-023a). These regulatory alternatives reflect the different levels of
emission control that were analyzed in determining best demonstrated
technology, considering costs, nonair quality health, and environmental
and economic impacts for onshore natural gas processors. These
alternatives remain the same.
1.2.2 Environmental Impacts of the Promulgated Action
The recommended standards would reduce atmospheric emissions of S0«
from about 39 newly constructed sweetening facilities by about
62,500 megagrams per year (68,900 tons per year) in the fifth year of
implementation. Implementation of the standards will not result in any
adverse solid waste impact or water impact.
1.2.3 Energy and Economic Impacts of the Promulgated Action
Energy impacts resulting from the standard are discussed in Chapter 7
of the Volume I BID and have not changed significantly since proposal.
The revised economic impact analysis, incorporating assumptions updated
since proposal, indicates that no adverse economic impacts on projected
facilities are expected to result from the standards. This revised
analysis is discussed in Appendix A of this document.
1.2.4 Other Considerations
1.2.4.1 Irreversible and Irretrievable Commitment of Resources.
The regulatory alternatives defined in Chapter 6 of the Volume I BID
would not preclude the development of future control options nor would
they curtail any beneficial use of resources. The alternatives do not
involve short-term environmental gains at the expense of long-term
environmental losses. The alternatives yield successively greater
short- and long-term environmental benefits, with the alternative upon
which the final standards are based providing the greatest benefits.
Further, none of the alternatives result in the irreversible and
irretrievable commitment of resources. No changes in these considerations
have resulted since proposal of the standard.
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1.2.4.2 Environmental and Energy Impacts of Delayed Standards. As
discussed in Chapter 7 of the Volume I BID, delay in the standard would
cause a similar delay in realizing the beneficial impacts associated
with the standard. No changes in the potential effects of delaying the
standard have occurred since proposal.
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2.0 SUMMARY OF PUBLIC COMMENTS
This document includes responses to public comments on the proposed
standards received in a total of thirty-one (31) letters and five
(5) public hearing presentations. The public hearing was held on March 7,
1984. A list of the cotnmenters, their affiliations, and the EPA docket
numbers assigned to their correspondence is given in Table 2-1.
For the purpose of orderly presentation, the comments have been
categorized under the following topics:
1. Need for Standards,
2. Applicability of the Standard,
3. Definitions,
4. Emission Control Technology,
5. Selection of Model Plants,
6. Economic Impact Analysis,
7. Cost-Effectiveness Analysis,
8. Small Plant Exemption,
9. Catalyst Life,
10. 1000°F Temperature Requirement,
11. Format of the Standard,
12. Monitoring and Performance Test Requirements,
13. Recordkeeping and Reporting Requirements,
14. Difference in State and NSPS Requirements, and
15. Miscellaneous Comments.
The comments, the issues they.address, and responses to each comment
are discussed in the following sections of this document.
2.1 NEED FOR STANDARDS
Comment: Several commenters (IV-F-1, IV-F-3, IV-F-5, IV-D-8,
IV-D-10, IV-D-11, IV-D-13, IV-D-28, IV-D-29, and IV-D-30) stated that
the proposed standards are unnecessary because the natural gas production
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Table 2-1. LIST OF COMMENTERS ON PROPOSED STANDARDS FOR
ONSHORE NATURAL GAS PROCESSING: S02 EMISSIONS
Docket item number Commenter and affiliation
IV-D-1 J. D. Reed
Standard Oil Company (Indiana)
200 East Randolph Drive
Chicago, Illinois 60601
Date: February 14, 1984
IV-D-2 Richard E. Grusnick
Alabama Department of
Environmental Management
1751 Federal Drive
Montgomery, Alabama 36130
Date: February 14, 1984
IV-D-3 R. E. Cannon
Gas Processors Association
1812 First Place
Tulsa, Oklahoma 74103
Date: March 2, 1984
IV-D-4 J. D. Geiger
Ami noil USA
Post Office Box 94193
Houston, Texas 77292
Date: March 7, 1984
IV-D-5 Lyman Yarborough
Amoco Production Company
16945 Northcase Drive
Houston, Texas 77210
Date: March 3, 1984
IV-D-6 H. K. Holland, Jr.
Mobil Oil Corporation
150 East 42nd Street
New York, New York 10017
Date: March 2, 1984
aThe docket number for this project is A-80-20A. Dockets are on
file at EPA Headquarters in Washington, D.C. and at the Office of
Air Quality Planning and Standards in Durham, North Carolina.
(continued)
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Table 2-1. Continued
Docket item number3 Commenter and affiliation
IV-D-7 Robert P. Miller
Robert P. Miller
Michigan Department of Natural
Resources
Stevens T. Mason Building
Box 30028
Lansing, Michigan 48909
Date: March 30, 1984
IV-D-8 Howard Reiquam
El Paso Natural Gas Company
Post Office Box 1492
El Paso, Texas 79978
Date: April 2, 1984
IV-D-9 John W. Graves
Pennzoil Company
Pennzoil Place
Post Office Box 2967
Houston, Texas 77252-2967
Date: April 6, 1984
IV-D-10 Peter W. McCallum
The Standard Oil Company
Midland Building
Cleveland, Ohio 44115-1098
Date: April 5, 1984
IV-D-11 B. L. Walters, Jr.
Marathon Oil Company
Find! ay, Ohio 45840
Date: April 4, 1984
IV-D-12 Randy L. Pitre
Cities Services Oil and Gas
Corporation
Box 3908
Tulsa, Oklahoma 74102
Date: April 6, 1984
aThe docket number for this project is A-80-20A. Dockets are on
file at EPA Headquarters in Washington, D.C. and at the Office of
Air Quality Planning and Standards in Durham, North Carolina.
(continued)
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Table 2-1. Continued
Docket item number Commenter and affiliation
IV-D-13 Hugh B. Barton
Exxon Company, USA
Post Office Box 2180
Houston, Texas 77001
Date: April 12, 1984
IV-D-14 Howard Reiquam
El Paso Natural Gas Company
Post Office Box 1492
El Paso, Texas 79978
Date: April 23, 1984
IV-D-15 Steven F. Kurmas
Michigan Consolidated Gas
Company
500 Griswold Street
Detroit, Michigan 48226
Date: April 25, 1984
IV-D-16 H. Schuyten
Chevron USA, Incorporated
575 Market Street
San Francisco, California 94120
Date: May 22, 1984
IV-D-17 Bill Stewart
Texas Air Control Board
6330 Highway 290 East
Austin, Texas 78723
Date: May 25, 1984
IV-D-18 0. P. Keehan
Mobil Oil Corporation
150 East 42nd Street
New York, New York 10017
Date: May 30, 1984
IV-D-19 R. E. Cannon
Gas Processors Association
1812 First Place
Tulsa, Oklahoma 74103
Date: June 1, 1984
aThe docket number for this project is A-80-20A. Dockets are on
file at EPA Headquarters in Washington, D.C. and at the Office of
Air Quality Planning and Standards in Durham, North Carolina.
(continued)
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Table 2-1. Continued
Docket item number3 Commenter and affiliation
IV-D-20 J. Donald Annett
Texaco USA
1050 17th Street, Northwest
Suite 500
Washington, D.C. 20036
Date: June 5, 1984
IV-D-21 Jack G. Sevenson
Rocky Mountain Oil and Gas
Association, Incorporated
345 Petroleum Building
Denver, Colorado 80202
Date: June 5, 1985
IV-D-22 Frank J. Duffy
Northern Gas Products Company
2223 Dodge Street
Omaha, Nebraska 68102
Date: June 5, 1984
IV-D-23 R. J. Cinq-Mars
Cities Service Oil and Gas
Corporation
Box 300
Tulsa, Oklahoma 74102
Date: June 1, 1984
IV-D-24 A. G. Smith
Shell Oil Company
One Shell Plaza
Post Office Box 4320
Houston, Texas 77210
Date: June 6, 1984
IV-D-25 J. D. Geiger
Ami noil USA
Post Office Box 94193
Houston, Texas 77292
Date: June 1, 1984
aThe docket number for this project is A-80-20A. Dockets are on
file at EPA Headquarters in Washington, D.C. and at the Office of
Air Quality Planning and Standards in Durham, North Carolina.
(continued)
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Table 2-1. Continued
Docket item number Commenter and affiliation
IV-D-26 Howard Reiquam
El Paso Natural Gas Company
Post Office Box 1492
El Paso, Texas 79978
Date: June 4, 1984
IV-D-27 P. J. Early
Amoco Production Company
200 East Randolph Drive
Post Office Box 5340A
Chicago, Illinois 60680
Date: June 5, 1984
IV-D-28 Lawrence J. Ogden
Interstate Natural Gas
Association of America
1660 L Street, Northwest
Washington, D.C. 20036
Date: June 6, 1984
IV-D-29 John G. Blackburn, Jr.
American Petroleum Institute
1220 L Street, Northwest
Washington, D.C. 20005
Date: June 6, 1984
IV-D-30 J. J. Moon
Phillips Petroleum Company
Bartlesville, Oklahoma 74004
Date: June 5, 1984
IV-D-31 L. T. Reed
Warren Petroleum Company
Post Office Box 1589
Tulsa, Oklahoma 74102
Date: June 5, 1984
aThe docket number for this project is A-80-20A. Dockets are on
file at EPA Headquarters in Washington, D.C. and at the Office of
Air Quality Planning and Standards in Durham, North Carolina.
(continued)
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Table 2-1. Concluded
Docket item number3 Commenter and affiliation
IV-F-1 R. L. Reed
Gas Processors Association
1812 First Place
Tulsa, Oklahoma 74103
Date: March 7, 1984
IV-F-2 Randy G.- Abernathy
Goar, Arrington and Associates,
Incorporated
Post Office Box 6947
Tyler, Texas 75711
Date: March 7, 1984
IV-F-3 Gary E. Reed
Texas Oil and Gas Corporation
Fidelity Union Tower
Dallas, Texas 75201
Date: March 7, 1984
IV-F-4 Louis Roberts
Texas Air Control Board
6330 Highway 290 East
Austin, Texas 78723
Date: March 7, 1984
IV-F-5 C. R. Kreuz
(On behalf of)
American Petroleum Institute
150 East 42nd Street
New York, New York 10017
Date: March 7, 1984
The docket number for this project is A-80-20A. Dockets are on
file at EPA Headquarters in Washington, D.C. and at the Office of
Air Quality Planning and Standards in Durham, North Carolina.
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industry does not contribute significantly to nationwide S02 emissions.
Commenters IV-F-5 and IV-D-13 cited an EPA document (National Air
Pollutant Emission Estimates) as providing data indicating that in 1980
the natural gas production industry accounted for 3.6 percent of
industrial S02 emissions and 0.4 percent of all anthropogenic S02
emissions.
Response: The crude oil and natural gas production industry is a
significant source of S02 emissions. Sweetening units and sulfur recovery
units are the primary contributors of the total S02 emissions from this
source category. In the analysis supporting the proposed standard, the
Agency estimated based on a projected growth of 44 new sweetening units
and sulfur recovery units with a sulfur feed rate of 1.0 LT/D or more,
that S02 emissions would increase by approximately 110,000 megagrams per
year (121,000 tons per year) by the fifth year in the absence of these
standards.* This estimate is based on detailed studies of individual
natural gas processing units and the emission reduction currently required
under State implementation plans (SIP). One hundred ten thousand Mg/year
is a significant quantity of S02 to be emitted as air pollution.
The significance of S02 emissions from the crude oil and natural
gas production industry is reflected in the Priority List, 40 CFR 60.16.
The Priority List consists of categories of air pollution sources that,
in EPA's judgment, cause or contribute significantly to air pollution
which may reasonably be anticipated to endanger public health or welfare.
Of the 59 major source categories on this list, the crude oil and natural
gas production industry source category ranked 29th. Commenters have
not presented any new information which would change the decision to
list the crude oil and natural gas production industry on the Priority
List.
It should be noted that because S02 emissions come from a large
number of diverse source categories, many source categories contribute a
relatively small percentage to the large overall total emissions. Even
*A revised analysis in support of the promulgated standard projects
39 affected facilities and an emissions increase in the fifth year of
76,600 Mg/yr in the absence of the standards.
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though natural gas processing plants may represent a small percentage of
total emissions, the magnitude of emissions from natural gas processing
plants is significant.
Since the crude oil and natural gas production industry is on the
Priority List as a significant contributor to air pollution under
Section lll(f) of the Clean Air Act (The Act) as amended in 1977, standards
of performance were required to be promulgated for those new sources
within this source category for which the EPA can identify the best
demonstrated technology (BDT) considering costs. The EPA has identified
several alternative systems of control capable of achieving additional
emission reduction at reasonable cost at natural gas processing plant
sources. It is, therefore, reasonable for EPA to establish standards
for these sources.
Comment: Several commenters (IV-F-1, IV-F-5, IV-D-8, IV-D-10,
IV-D-13, IV-D-18, IV-D-19, IV-D-20, IV-D-22, IV-D-25, IV-D-26, IV-D-28,
IV-D-29, and IV-D-30) stated that there is no need for the standards
because S02 emissions from sweetening and sulfur recovery units are
adequately controlled by other regulations, specifically prevention of
significant deterioration (PSD) regulations and SIP requirements.
Several States were cited as having existing regulations equivalent to
at least Alternative II and often exceeding Alternative III. As a
result, the standards are considered to be unnecessary and to needlessly
cause an increase in natural gas production costs (IV-F-1).
Response: New source performance standards (NSPS) required by
Section 111 play a unique role under the Clean Air Act. The main purpose
of NSPS is to require new, modified, and reconstructed sources to reduce
emissions to the level achievable by the best technological system of
continuous emission reduction. Consideration must be given to the cost
of achieving such emission reduction, any nonair quality health and
environmental impacts, and energy requirements [Section lll(a)(l)].
Congress recognized that establishing such standards would minimize
increases in air pollution from new sources, thereby improving air
quality as the Nation's industrial base is replaced over the long term.
The role of NSPS in achieving the goals set forth in the Act is distinct
from that of other regulations.
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The PSD requirements serve a different but complementary role to
new source performance standards. The PSD requirements are designed to
protect local air quality values and to ensure that air quality does not
significantly deteriorate. The PSD requirements may vary according to
air quality conditions in the specific area of the plant, whereas NSPS
provide a uniform minimum requirement based on BDT for a particular
emission source category, irrespective of local air quality conditions
or values. The NSPS serve to establish the minimum requirements for new
and mofified sources subject to PSD. At their discretion, States may
elect to require greater emission reductions than would be achieved
under NSPS in order to make more room for future industrial growth or to
afford a higher level of air quality protection in a given area. In
most instances, however, the level of control required under PSD does
not exceed the level of control required under NSPS and, in fact, is
established based on information obtained as a result of the development
of NSPS.
The EPA estimates that these standards will reduce S02 emissions
from the natural gas production industry by about 62,500 megagrams per
year (68,900 tons per year) in the fifth year of implementation compared
to existing SIP requirements. This represents a reduction in S02
emissions of 76 percent from SIP levels. The Agency considers such an
emission reduction as significant and believes that standards that
achieve such reductions are warranted.
In addition, many PSD determinations and SIP's governing S02
emissions do not address control of small plants. These plants constitute
a significant proportion of S02 emissions. Based on projected baseline
(SIP) control levels (1982 to 1987), emissions of S02 from onshore
natural gas processing plants with sulfur feed rate capacities from less
than 1 LT/D to 5 LT/D account for 25 percent of projected industry wide
S02 emissions. Most of these emissions would be controlled by the NSPS.
Comment: The commenter (IV-D-20) stated that the proposed standards
should be withdrawn because the Agency has overestimated the magnitude
of S02 emissions from onshore natural gas processing plants, overestimated
the impacts of S02 emissions from such sources on public health and
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welfare, overestimated the emissions reductions that would be accomplished
by the standards, and underestimated the economic impact on the oil and
gas production industry, especially in the case where small quantities
of H2S are being removed from gas streams and are being combusted. No
specific data were supplied by the commenter to substantiate these
statements.
Response: Because onshore natural gas processing plants are a
subcategory of the Crude Oil and Natural Gas Production Industry source
category, listed as 29th on the NSPS Priority List, the Act requires EPA
to promulgate standards. The Priority List ranks major source categories
according to criteria' specified in Section lll(f) of the Act. One of
these criteria is "the extent to which each pollutant endangers public
health or welfare." Sulfur dioxide has been well established as a
pollutant having adverse effects on health and welfare. There are
National Primary and Secondary Ambient Air Quality Standards for S02-
Also, S02 is recognized as a precursor to acid rain (Docket Entry IV-J-3).
As stated in the response to previous comments, the magnitude of
emissions from natural gas processing plants is significant. Estimates
of S02 emissions from these sources were based on data received from the
industry. Nationwide S02 emissions from the existing industry are
estimated to be 250,000 Mg/year.
The Agency's estimation of emissions reductions that would be
accomplished by the standard represents a comparison between Regulatory
Alternative III requirements and baseline emissions. The baseline
values reflect typical SIP levels. The S02 emission reduction
attributable to the standard has been estimated to be 62,500 Mg/yr
(68,900 tons/yr) in the fifth year after promulgation.
For a discussion of economic impact estimations, the commenter is
referred to Section 2.6 of this volume.
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2.2 APPLICABILITY OF THE STANDARD
Several commenters requested clarification of the applicability of
the standard.
Comment: Two commenters (IV-F-1 and IV-D-16) believed that much of
the C02 from enhanced oil recovery plants would have to be sweetened
before reinjection as a result of the proposed definition of "sweetening
unit" and suggested a clarification such that the standards apply only
to those sweetening units which release acid gas into the atmosphere.
Comment: The commenter (IV-D-18) requested that facilities whose
primary purpose is to handle and/or cycle C02 for enhanced oil recovery
be exempted from the standard, even though H2S is associated with the
C02. The commenter claimed that a C02 plant may be affected by the
standard if the sulfur feed rate exceeds the minimum level, although all
the sulfur-containing gas may be reinjected into a reservoir.
Comment: Three commenters (IV-D-19, IV-D-27, and IV-D-31)
recommended exempting C02 and H2S streams that are processed through a
sweetening unit and are then injected for recovery of oil because sulfur
compounds are not released to the atmosphere in that process. One of
these commenters (IV-D-27) also suggested an exemption for these
facilities when the acid gas stream is delivered to another company.
Response: The standard has been amended to clarify that affected
facilities are those sweetening units (including sweetening units followed
by sulfur recovery plants) that emit some or all of the acid gas stream
to the atmosphere. An applicability provision has been added in
§60.640(e) that reads, "The provisions of this subpart do not apply to
sweetening facilities producing acid gas that is completely reinjected
into oil-or-gas-bearing geologic strata or that is otherwise not released
to the atmosphere."
Comment: Another commenter (IV-D-2) requested clarification on the
applicability of the standard as to whether the minimum plant size
affected is measured in terms of sulfur available as H2S or as sulfur.
Response: Paragraph 60.640(b) has been changed to clarify that the
minimum plant size is measured in terms of sulfur, as intended in the
proposed standard.
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Comment: Two commenters (IV-F-4 and IV-D-17) requested clarification
of the designation of affected facility as it applies to onshore plants
processing natural gas produced offshore.
Response: Paragraph 60.640(c) has been revised to state that
sweetening units and sulfur recovery units that process natural gas
produced from either onshore or offshore wells are covered by the
standards. Paragraph 60.640(c) now reads, "The provisions of this
subpart are applicable to facilities located onshore which process
natural gas produced from either onshore or offshore wells."
Comment: Two commenters (IV-D-13 and IV-D-18) requested a
clarification of paragraph 60.640(c) as to whether the reference to
"offshore" refers to the outercontinental shelf (OCS) or to facilities
located on a platform in inland coastal marshes or bays.
Response: The standards were intended to exclude sweetening units
and sulfur recovery units located on offshore platforms on the OCS.
Facilities located on platforms in inland coastal marshes and bays are
subject to the standards. An attempt was made by the Agency to obtain
information regarding costs for sweetening units and sulfur recovery
units constructed on platforms in inland coastal marshes and bays. The
data obtained were not sufficient to determine what the costs would be
for such units or whether they would be significantly different from the
costs assumed in the Agency's cost analyses. One industry representative
indicated that the construction of sweetening units or sulfur recovery
units on rigs in inland coastal marshes and bays would be highly unlikely
(Docket Entry IV-E-4). To clarify the definition of "onshore," §60.641
has been revised to read, "Onshore means all facilities except those
that are located in the territorial seas or on the outercontinental
shelf."
Comment: The commenter (IV-D-9) recommends that the iron oxide
method (i.e., "iron sponge" method) for H2S removal be explicitly exempted
from the proposed standard. The commenter stated that these units are
usually used to recover very small amounts of sulfur and are already
exempted from regulations in the State of Texas.
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Response: The Agency does not regard the use of a particular
technology as an appropriate basis for exempting facilities from these
standards. The EPA analyzed the cost effectiveness of various sulfur
recovery technologies for a range of sulfur feed rates. For smaller
feed rates, the 2-stage Recycle Selectox was used as a representative
technology for the purpose of estimating the cost effectiveness of the
proposed standards. The cost of using the iron oxide method of hydrogen
sulfide removal was not specifically analyzed.
The commenter's suggestion was not accepted for two reasons.
First, the EPA's analysis of cost effectiveness indicates that 2.0 long
ton per day (LT/D) of sulfur feed rate is an appropriate cutoff regardless
of the sulfur recovery technology used. Feed rate is a much more
significant factor influencing cost effectiveness than the difference in
control cost for various technologies. In any case, demonstrated
technologies with acceptable costs are available for use in reducing S02
emissions from plants with sulfur feed rates of 2.0 LT/D or more.
Second, Section lll(b)(2) of the Act authorizes EPA to distinguish
among classes, types, and sizes within categories of new sources for the
purpose of establishing standards. Excluding facilities based on size
because of unreasonable cost impacts, as done in these standards, is an
appropriate basis for excluding small facilities.
Under these standards, small plants (less than 2.0 LT/D sulfur feed
rate) are exempt regardless of the sulfur recovery process used. If all
or most plants below that size use the iron oxide method, then such
plants will be exempt from the standards based on their low sulfur feed
rate.
Comment: Three commenters (IV-D-13, IV-D-27, and IV-D-29) requested
that a paragraph be added to §60.646 of the proposed standards to indicate
that installation of equipment for process improvement (accomplished
without capital expenditure) not be considered a modification. The
commenter cited a similar section in 40 CFR 60.630(c), the proposed
standards for equipment leaks of VOC from onshore natural gas processing
plants.
Response: Under the General Provisions of 40 CFR Part 60, any
physical or operational change to an existing facility which results in
an increase in the emission rate of any pollutant may be considered a
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modification within the meaning of Section 111 of the Act. Such physical
or operational changes constitute modifications subject to NSPS unless
covered under one of the general exemptions of §60.14(e) or expressly
exempted under the standards applicable to the source category.
The proposed VOC standards for onshore natural gas processing
plants (49 FR 2636, January 20, 1984) included a specific exemption for
the "addition or replacement of equipment for the purpose of process
improvement that is accomplished without a capital expenditure. . ."
[§60.630(c)j. This special exemption was included because of the
anticipated replacement of numerous valves, gaskets, and other small
pieces of equipment for the purpose of process improvements. These
changes are directly related to leaks of VOC and, therefore, could
result in an emissions increase from the process unit, thereby causing
the entire process unit to be subject to the standards under the
modification rule. By including an express exemption for these small
changes that can be accomplished, in most cases, without a capital
expenditure, the Agency intended to clarify that such changes would not,
by themselves, constitute modifications.
In the case of the S02 standards, the General Provisions already
include exemption provisions that sufficiently address likely equipment
changes related to S02 emissions. Section 60.14(e)(l) provides that
maintenance, repair, and replacement which the Administrator determines
to be routine for the source category shall not be considered
modifications. Section 60.14(e)(2) provides that an increase in the
production rate of an existing facility that can be accomplished without
a capital expenditure also shall not be considered a modification subject
to NSPS.
Because numerous small non-capital changes that would result in an
emission rate increase are not anticipated with sweetening or sulfur
recovery units, the Agency is not aware of any circumstances that warrant
an exemption similar to that provided in the VOC standards. The general
exemption provisions of paragraphs 60.14(e)(l) and (2) currently provide
an adequate means for exempting changes involving small pieces of
equipment. For this reason, the commenter's recommendations were not
included in the S02 standards.
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Comment: One commenter (IV-D-13) requested that the standard, if
it is promulgated, be made effective (sic) 12 months after the final
publication in the Federal Register to avoid uncertainties regarding
plant construction after January 20, 1984. Another commenter (IV-D-18)
recommended changing the standard's effective date to 180 days after the
date of adoption.
Comment: The commenter (IV-D-29) recommended that the Administrator
publish in the Federal Register an official notice of retraction of the
January 20, 1984 effective date (sic) for purposes of the definition of
a "new source." The commenter claimed that failure to do so would
impose unnecessary burdens in industry because any planning or design
work begun after the publication date must incorporate the elements of
the proposed standard which have not yet become requirements. He further
stated that Section lll(b)(l)(B) requires the Administrator to promulgate
a standard within 90 days of publication of a proposal, and that review
of comments can result in delays past the 90 day period. He claimed
that the Agency had the authority to mitigate the inequity associated
with any delay past 90 days necessary for reasoned decisionmaking.
Response: Proposal of the standards is legal notification that an
owner or operator of an affected facility will be subject to the standards.
Affected facilities are those for which construction, modification, or
reconstruction is commenced on or after the applicability date, i.e.,
the date of proposal in the Federal Register. The Act [Section lll(a)(2)]
clearly states the Congressional intent that the proposal date will be
the applicability date. The applicability date should be distinguished
from the effective date of the regulation, which is the date on which
the standards become legally enforceable. Under Section lll(b)(l)(B) of
the Act, the effective date is the date of promulgation (i.e., final
publication in the Federal Register).
The proposal date is the applicability date unless the promulgated
(or revised) standard is not based on and achievable by the same
technology specified at proposal. This decision is consistent with the
EPA's practice of applying NSPS to all sources built after proposal
where the promulgated (or revised) standards are based on and achievable
by the same technology as the proposed standards.
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Section lll(a)(2) implements the basic Congressional objective of
preventing new pollution problems and improving air quality as industry
changes by requiring all new sources, built or modified after proposal,
to use BDT in achieving emissions reductions. Congress recognized the
existence of some uncertainty as to the final standards that this
technology must meet [S. Rep. No. 91-1196, 91st Cong. 2d sess; Senate
Bill, §113(b)(2)]. The passage of time between identification of BDT as
the basis of a standard and the final specification of the performance
required of that technology, therefore, is not relevant by itself.
Under Sections lll(b)(l)(B) and 307(d)(10), an NSPS should be promulgated
within 6 months of proposal. However, Congress did not intend that if
promulgation took longer, the category of new sources should change,
Commonwealth of Pennsylvania v. EPA, 618 F. 2d 991, 1000 (3rd Cir.
1980); 45 FR 8210, 8232 (February 6, 1980); United States v. City of
Painesville, 644 F. 2d 1186 (6th Cir. 1981), cert. den. 102 S. cit. 392
(1981); 49 FR 18076 (April 26, 1984).
The basic conclusion of the Agency is that the applicability date
should not change except as necessary to prevent unreasonable costs.
Neither uncertainty as to whether the Agency will promulgate the standard,
nor substantial delay in promulgating the standard justifies postponing
the applicability date.
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2.3 DEFINITIONS
Two commenters requested clarification of the definitions of certain
terms in the preamble and the proposed regulation.
Comment: One commenter (IV-F-2) requested that a reference pressure
and temperature be added to the proposed regulation to define "standard
cubic foot" of gas.
Response: In accordance with the definition of "Standard Conditions"
given in the General Provisions, standard temperature means 293K (68°F);
standard pressure means 101.3 kilopascals (29.92 in. Hg). Because the
definition is presented in the General Provisions, it is not necessary
to repeat it in each subpart.
Comment: The commenter (IV-F-2) stated that the mole percent H2S
in the acid gas should be defined on a wet basis because in its actual
state coming from the sweetening unit the acid gas is saturated with
water, usually 5 to 10 mole percent H20.
Response: The mole percent H2S in the acid gas from the sweetening
unit was defined on a dry basis for two reasons. First, the mole percent
H2S data used in the analysis to yield the sulfur recovery efficiency
equations were collected on a dry basis. Second, the Tutwiler method
commonly used to determine the mole percent H2S in the acid gas yields
data on a dry basis. Consequently, the dry basis for the mole percent
H2S was retained in the standards to ensure consistency with the basis
for the efficiency equations and with measurements obtained according to
the Tutwiler method.
Comment: Four commenters (IV-D-13, IV-D-18, IV-D-27, and IV-D-29)
stated that there was an inconsistency in the use of the term
"1.0 long ton per day of hydrogen sulfide (H2S) in the acid gas" in
paragraphs 60.640(b), 60.641, and 60.647(c). One of the commenters
suggested that the phrase be changed to "1.0 long ton per day of H2S in
the acid gas, expressed as sulfur."
Response: The standards were revised to incorporate the phrase
"H2S (in the acid gas) expressed as sulfur," in §§60.640, 60.641,
and 60.647, per the commenters1 suggestion.
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Comment: The commenter (IV-D-13) suggested that the definition of
"acid gas" be revised to clarify that acid gas means the outlet stream
of a sweetening unit. The commenter recommended the following definition:
"Acid gas means a stream of hydrogen sulfide (H2S) and carbon
dioxide (C02) that has been separated from sour natural gas by a
sweetening unit."
Response: The standards were revised in §60.641 to incorporate the
definition of acid gas suggested by the commenter.
Comment: The commenter (IV-D-13) suggested that the definition of
sulfur production rate be changed to the following: "Sulfur production
rate means the rate of liquid sulfur (elemental sulfur with a molecular
weight of 256) accumulation from the sulfur recovery unit."
Response: The commenter was contacted to ascertain the purpose of
his comment. He indicated that the intent of the comment was to ensure
consistency in measurement of sulfur production and theoretical recovery
calculations and to distinguish between liquid sulfur, S8 (molecular
weight 256) and atomic sulfur, S (molecular weight 32).
All sulfur measurements will be made in terms of liquid sulfur (S8)
and the Agency does not think it is necessary to define sulfur in terms
of its molecular weight. Therefore, the definition of sulfur production
weight was not changed.
Comment: The commenter (IV-D-13) suggested that clarification of
whether auxiliary or adjacent plant equipment is included in the terms
"sulfur recovery unit" and "sweetening unit" might be desirable. The
commenter noted that the scope of these definitions could have a
significant impact on whether changes in such auxiliary or adjacent
equipment would constitute modifications subject to the proposed standards.
The commenter, however, expressed satisfaction with the definitions of
"sulfur recovery unit" and "sweetening unit" as proposed, which the
commenter understood to exclude equipment not essential to the sweetening
or recovery process.
Response: All equipment that is essential to the gas sweetening or
sulfur recovery process is part of the affected facility under these
standards. For example, the definition of sweetening unit includes all
essential components of the sweetening process such as the gas contactor
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or solvent absorber, solvent regeneration columns, pumps, coolers, and
condensers. Auxiliary or adjacent equipment that is not an integral
component of a sweetening unit or sulfur recovery unit is not considered
part of the affected facility. Consequently, changes to such equipment
would not constitute a modification that would bring an existing
sweetening or sulfur recovery unit within the coverage of these standards.
Comment: The commenter (IV-D-29) stated that a definition for
"capital expenditure" should be added to the standard. The commenter
stated that 40 CFR Part 60 defines capital expenditure as a fixed
percentage of the "cost basis" as defined by the IRS and stated that the
value is used to establish the cost threshold of a process improvement
modification that would cause a plant to come under the NSPS. He claimed
that many old gas plants were constructed at costs below today's cost
and the "cost basis" is therefore low. He also claimed that IRS
Publication 543 establishes the fixed percentage repair allowance for
gas plants at 4.5 percent, which is low compared to that for refinery
equipment (7 percent) and onshore exploration equipment (10 percent).
He claimed that a low "cost basis" and low repair allowance percentage
would discourage process improvement and perpetuate less efficient
operations. He recommends adding a definition that raises the fixed
percentage repair allowance to 10 percent.
Response: The EPA acknowledges that costs have increased over time
due to inflation and that the facility's "cost basis" does not reflect
today's costs. Also, the older a plant is, the more likely it is that a
change causing an emission rate increase and involving a production rate
increase could also involve a capital expenditure (the three conditions
that would have to be met in the commenter's example before the facility
would come under the NSPS as a modification). One purpose of the
modification provision is to prevent continual changes to old high-
emitting facilities that serve to prolong the life of the old facility
•while circumventing emission control requirements. Thus, it is
appropriate that changes to old facilities (those with a low cost basis
relative to today's cost) which increase the facilities' emission rates
should result in bringing the facilities under the NSPS.
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However, it should be noted that old facilities that are instituting
process improvements need not come under the modification provision. An
owner or operator can avoid coming under the modification provision by
making process improvements that do not, in themselves, cause an emission
rate increase or that do not result in an emission rate increase from
the facility because offsetting changes are made elsewhere in the affected
facility. It is only when there is an emission rate increase in addition
to a production rate increase that the captial expenditure criterion is
applicable in determining whether there is a modification, as defined in
§60.14 of the General Provisions. For this reason, the Administrator
does not believe that using the capital expenditure criterion, as defined
in the General Provisions (§60.2), necessarily discourages process
improvements or perpetuates less efficient operations.
In regard to the repair allowance percentage of 4.5 for natural gas
processing plants, the 4.5 percent Annual Asset Guideline Repair Allowance
Percentage (AAGRAP) for a natural gas processing plant is established by
the IRS, and its applicability to NSPS is established in the General
Provisions. Because the AAGRAP is determined by the IRS to be an
appropriate depreciation parameter for determining tax liability, EPA
considers it an appropriate basis for determining the maximum amount a
facility can reinvest for process maintenance and/or improvement purposes
without having made a "capital expenditure." The EPA recognizes that
other industries use different AAGRAP percentages. The AAGRAP values
are industry-specific based on the type of operations performed by the
industry and the expected repair expenses that the industry is likely to
incur. As such, the AAGRAP would require adjustment by the IRS and not
by EPA.
Comment: The commenter (IV-D-29) responded to a request made at
the public hearing (March 7, 1984, Docket Entry IV-F-6) for a definition
of small remote plants. The commenter stated that small remote plants
should be defined as those at which an operator can demonstrate that
skilled labor pools are not readily available.
Response: The Agency has extensively evaluated the potential
impacts of these standards on small plants and has concluded that cost,
economic, and other impacts of these requirements are reasonable for
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small plants processing at least 2 LT/D of sulfur. (Plants with sulfur
feed rates below 2 LT/D are not subject to these standards due to cost-
effectiveness considerations.)
The remote location of some plants has been addressed in the revision
to the standards that provides for sulfur measurements every 24 hours
instead of every 12 hours, as required at proposal. This revision
addresses the issue of remote plants which are unattended for 12 hours
of an operating day.
Because the provisions for small plants are applicable to all small
plants, irrespective of location, there is no need for a definition of
small remote plants. As a result, the definition suggested by the
commenter was not included in the regulation.
Comment: The commenter (IV-D-27) stated that metric units are used
in paragraph 60.641 and that the desired results could be obtained with
equal accuracy with any consistent units. He recommended that equivalent
calculations with any set of units be permitted.
Response: For consistency and clarity, metric units are used
throughout the standards, but calculations can be made in English units
and converted into metric units.
Comment: The commenter (IV-D-29) suggested adding a new definition
to §60.641 stating that '"process improvement1 means routine changes
made for safety and occupational health requirements, energy savings,
better utility, ease of maintenance and operation, correction of design
deficiencies, bottleneck removal, changing product requirements, or
environmental control."
Response: This comment is related to one made by commenter IV-D-19
recommending that installation of equipment for process improvement
purposes not be considered a modification. The term "process improvement"
does not appear in the regulation. Since the suggestion made in
comment IV-D-19 was not accepted, there is no need for a definition of
the term "process improvement" to be incorporated into the standards.
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2.4 EMISSION CONTROL TECHNOLOGY
Comment: One commenter (IV-F-2) stated that Table 1 on page 2660
of the preamble to the proposed standards might be interpreted to mean
that EPA is not recommending 2-stage or 3-stage Recycle Selectox units
for sulfur feed rates greater than 5 LT/D. The commenter stated that
2-stage and 3-stage Recycle Selectox units can be used for plants with
sulfur feed rates of greater than 5 LT/D.
Response: Table 1 in the proposed standard shows model plant and
control technology combinations for each regulatory alternative for the
purpose of estimating impacts of each alternative standard. The table
was not intended to be a recommendation on the best sulfur recovery
process for various sulfur feed rates. The selection of control
technologies for each regulatory alternative was based on the demonstrated
control technology that has the highest recovery rate within the range
of incremental cost effectiveness established for that particular
regulatory alternative. Based on this criterion, Recycle Selectox
2-stage and 3-stage sulfur recovery units were selected as representative
technologies for Regulatory Alternatives III to V for sulfur feed rates
below 5 LT/D. Above that feed rate, other technologies were identified
as having the greatest recovery efficiency within the ranges of
incremental cost effectiveness established. The selection of other
technologies for units with sulfur feed rates above 5 LT/D does not mean
that Recycle Selectox units are not suitable for these larger feed
rates.
Comment: One commenter (IV-F-2) questioned the accuracy of the
sulfur recovery values stated in the proposed standards for 2-stage and
3-stage Claus units. The commenter believed the efficiencies stated in
the proposed standards were too high and cited efficiencies from case
studies in Appendix E of the Volume I BID as support. Specifically, the
commenter noted that the proposed standards cited a 93.0 percent recovery
for 2-stage Claus units with an inlet concentration of 12.5 mole percent
H2S whereas Table 6-11 in Appendix E refers to an average recovery of
91.3 percent. The commenter stated that recoveries for 2-stage Claus
units with an inlet gas concentration of 12.5 mole percent H2S should be
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90 to 92 percent. The commenter also noted that the same table indicates
an average recovery of 93.93 percent for a 3-stage Claus unit under the
same conditions, whereas the proposed standards refer to a 94.7 percent
recovery.
Response: There is no discrepancy between the efficiencies referred
to by the commenter and cited by the Agency in the proposed standards.
The recovery percentage of 93.0 percent for 2-stage Claus units referred
to in the proposed standards is a start-of-run efficiency. The
commenter1s reference to 90 to 92 percent as the proper efficiency for
2-stage Claus units coincides with the Agency's average-of-run efficiency
of 91.3 percent cited in Chapter 4 of the BID. The end-of-run efficiency
for these units was determined to be 89.6 percent and the average-of-run
efficiency to be 91.3 (the average of 93.0 and 89.6 percent).
Similarly, the recovery percentage of 94.7 for 3-stage Claus units
with 12.5 mole percent H2S represents a start-of-run efficiency. The
93.93 percent recovery referred to by the commenter represents an
average-of-run efficiency.
Comment: The commenter (IV-F-2) added that a Claus unit cannot be
operated with an acid gas feed of only 12.5 mole percent H2S without
employing some special method of sustaining combustion, such as acid gas
feed preheating, oxygen injection, or recycle of product sulfur. The
commenter said that these methods are energy intensive, require
substantial capital investment, and are difficult to maintain. The
commenter stated that 30 to 35 mole percent H2S was required, as a
minimum, to sustain combustion. Finally, the commenter questioned the
practicality of using 2-stage or 3-stage Claus units to recover sulfur
from systems with acid gas feed rates less than 20 to 25 mole percent
H2S.
Response: The Agency understands that for acid gas streams with
H2S concentrations below about 50 mole percent, the conventional
straight-through Claus process experiences operating limitations, and
that process modifications incorporating split-flow configuration,
preheating of acid gas and air, and/or recycling of sulfur may be
required. As discussed in the Volume I BID, split-flow design is used
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for acid gas stream with about 20 to 50 percent H2S, preheated feed is
used in the 10 to 25 percent H2S range, and sulfur recycling (i.e., the
"sulfur burning process") is used below 10 percent H2S. Each of these
supplemental technologies for the Claus process has been employed in the
natural gas processing industry.
In its analysis of the costs of Claus units, EPA included the cost
of energy consumption and capital costs of model plants employing these
supplemental technologies to treat lean gas streams. For example, the
Claus process evaluated for the 12.5 mole percent H2S case referred to
by the commenter was a split-flow configuration with preheated feed
streams. Both the energy costs and the capital costs for a preheated
feed stream were included for this case. Based on this analysis of
Claus process costs, the Agency concluded that the total cost of Claus
units for 12.5 mole percent H2S is acceptable and that such units should
be'considered as one of several demonstrated technologies. The EPA
acknowledges the applicability of the Recycle Selectox technology to
leaner acid gas streams. For these leaner feed streams, Recycle Selectox
recovery units are considered to be comparable in overall performance
and cost to Claus units.
Comment: The same commenter (IV-F-2) recommended adding BSR/Selectox
to the list of candidates for BDT, based on actual operating experience
for a unit in West Germany, overall sulfur recovery efficiency, and
operating costs. The commenter stated that recoveries of 99 percent and
99.6 percent can be reached with BSR/Selectox and BSR/Selectox followed
by a final Claus stage, respectively, instead of the 97 percent and
98 percent recoveries given in the Volume I BID.
Response: In developing these standards, the Agency evaluated the
performance of the BSR/Selectox tail gas process. Based on a review of
data from the only industrial BSR/Selectox unit known to EPA, the
statements made by the commenter appear supportable. This new process
appears to be a reliable tail gas cleanup process capable of an overall
sulfur recovery of 97.84 to 98.49 percent (average-of-run) at a reasonable
cost. This compares to start-of-run efficiencies of 99 and 99.6 percent
cited by the commenter. The BSR/Selectox process is discussed in detail
in Chapter 4 of the Volume I BID.
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Owners or operators are free to select any technology that will
meet the standards applicable to their plant. The standards are based
on the performance capabilities of the best demonstrated technology,
considering cost, nonair quality health, and enviromental and energy
considerations. However, the standards neither require nor preclude the
use of any specific technology or process. There are a number of tail
gas cleanup technologies, including the BSR/Selectox process, available
for use in complying with these standards.
Comment: The commenter (IV-F-3) stated that the technical
feasibility of sulfur recovery for plants with sulfur feeds less than
3 LT/D is in question.
Response: Before proposing the cutoff, the Agency investigated
through the process designer and the Selectox catalyst manufacturer the
capabilities of the Recycle Selectox process. The key to successful
operation of small sulfur plants employing the Glaus reaction (2 H2S +
S02 —>• 3S + 2 H2S) is the maintenance of the 2 to 1 ratio of H2S to S02.
For this reason, particular attention was paid to the capabilities and
limitations of the Selectox catalyst used in the Recycle Selectox process
to oxidize H2S to S02. The catalyst manufacturer provided information
indicating that the catalyst effectively achieves 2 to 1 ratio
irrespective of the amount of sulfur available in the acid gas stream.
The technology has worked well at larger plants and there is no reason
why it should not work at smaller plants because catalyst performance
and the ratio of H2S to S02 do not depend on sulfur feed rate. On this
basis, the Agency concluded that sulfur recovery technologies are
technically feasible for plants with sulfur feeds less than 3 LT/D.
Comment: Two commenters (IV-D-12 and IV-D-29) claimed that sulfur
recovery technology is not currently available which can adequately
handle the daily production rate fluctuations typically experienced at
small facilities. The commenters further stated that production rates
are often controlled by regulatory agencies and pipeline transmission
companies and that those factors cause extensive fluctuations in
production rates, especially when just a few small wells are involved.
Other limiting factors mentioned were versatility of design for
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fluctuating flow rates and varying H2S/C02 ratios and shutdown of wells
for repair and service. Commenter IV-D-12 provided an analysis of best
available control technology (BACT) for a sulfur recovery unit for a
two-well operation. The conclusion reached in that analysis was that
flaring was the BACT for that operation.
Comment: Another commenter (IV-D-25) stated that the feed to a
natural gas plant varies constantly because producers are constantly
shutting in or reworking wells, and that for a small sulfur recovery
unit (15 LT/D or less) the fluctuation of the inlet stream has a
significant effect on efficiency of the unit. The commenter claimed
that a sulfur recovery unit can still operate when the acid gas volume
has been reduced by two-thirds, but the efficiency decreases significantly
and the unit requires constant attention by the operator to maintain
operation.
Comment: The commenter (IV-D-28) claimed that the technology for
recovering sulfur from acid gas streams with low H2S concentrations is
not well proven, and therefore, this raises serious questions as to
sulfur recovery efficiency, capital investment, and operating costs
associated with such plants.
Response: The Agency conducted an extensive review of available
sulfur recovery technologies prior to proposal. The Agency concluded
that demonstrated technologies exist that are technically and economically
feasible for use at facilities with greater than or equal to 1 LT/D
capacity. Specifically, for small plants (about 1.0 to 5.0 LT/D), the
2-stage Recycle Selectox technology was determined to be applicable.
The Recycle Selectox process has been employed on acid gas streams as
lean as 2 percent H2S, and a start-of-run recovery efficiency of
80.68 percent has been reported (Table H-6, BID). On this basis,
demonstrated technologies are considered to be available for small
plants and extremely lean acid gas streams. Further, the Recycle Selectox
process with standard instrumentation can meet required recovery
efficiencies when operating at one-third or less of design capacity.
With dual instrumentation and control valves, at an added cost of 2 to
5 percent of the total plant cost, efficiencies can be maintained at
levels as low as 10 to 20 percent of capacity (Reference Docket
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Entries II-D-58 and IV-E-1). This capability allows sufficient process
control to accommodate the feed rate fluctuations of typical small
sulfur recovery plants, which generally do not vary more than 100 to
200 percent.
Capital investment and operating costs were provided by the
Ralph M. Parsons Company and incorporate the normal contingencies used
in costing. The Agency used standard industry practices for costing
techniques.
Comment: The commenter (IV-D-7) suggested that proven technologies
such as single-stage Claus units and caustic scrubbers be included as
BDT in addition to the technologies considered in the proposed standard.
The commenter cited sulfur recovery efficiencies of up to 85 percent for
a single-stage Claus unit; greater than 95 percent for 2-stage counter-
current caustic scrubbers (91 to 94 percent normal operating efficiency);
and greater than 85 percent for a single-stage caustic scrubber.
Response: The Agency acknowledges that single-stage Claus units
and caustic scrubbers are proven sulfur recovery technologies that are
available for use in meeting these standards. Single-stage Claus units
were not selected as BDT because their sulfur recovery efficiencies are
generally lower than other demonstrated technologies. Two-stage Claus
units are capable of attaining recovery efficiencies between 93.0 percent
(with a 12.5 percent H2S concentration) and 96.3 percent (with an
80 percent H2S concentration). A 3-stage Claus unit increases sulfur
recovery to between about 94.7 percent (with a 12.5 percent H2S
concentration) and 97.3 percent (with an 80 percent H2S concentration).
These efficiencies compare to recovery efficiencies of 85 percent cited
by the commenter for single-stage Claus units. Cost information provided
by the commenter and in subsequent discussions with the Ralph M. Parsons
Company (Docket Entry IV-B-8) indicate that the single-stage Claus unit
costs approximately 10 percent less than the units designated as
representative of BDT for comparable plant sizes.
During the development of the standards, the Agency had little
information on the application of caustic scrubbers to sulfur recovery
in the gas processing industry. For this reason, this technology was
not fully evaluated. Data provided by the commenter and in subsequent
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preliminary investigations by the Agency (Docket Entry IV-B-8) indicate
that the technology scrubs H2S from the sour or acid gas streams with an
aqueous caustic solution and the sulfur is removed from the process in
the form of sodium hydrosulfide in the spent caustic solution. The
economic success of the technology appears to be dependent upon the
ability of operators to sell the spent absorbent and thereby recoup
operating expenses (i.e., cost of caustic) and avoid disposal costs.
The facilities known to the Agency reportedly use railroad tank cars to
transport their spent absorbent to a paper mill where the absorbent is
used to make up chemicals for the kraft pulping process.
The technologies recommended by the commenter could be used to meet
these standards provided they achieve the required emission reduction
efficiency. The use of single-stage Claus units or caustic scrubbers is
not precluded by these standards, nor is any specific technology required
to be used.
Comment: The commenter (IV-D-7) recommended investigation of
two new control technologies, the LoCaty.. and $lurrisweetyM processes.
According to the commenter, the LoCat.,.. process is essentially 100 percent
efficient in sulfur removal and can be used to replace an amine sweetening
unit or as a tail gas unit. Two LoCatyM facilities reportedly have been
proposed for construction in Michigan. The commenter reported that
Slum'sweet-,,, is limited to use on gas streams with relatively low H2S
concentrations, but is suited for streams previously handled by small or
medium sized amine plants. Three Slum'sweety., facilities have been
permitted, one of which is operating and reportedly performing well.
Response: As the standards were developed, the Agency reviewed the
LoCatyM and Slum'sweety., processes and their applicability for sulfur
removal. At that time, concrete data were not available to evaluate the
effectiveness, cost, and applicability of the two new technologies.
Data provided by the commenter indicate that the two technologies may
achieve sulfur recoveries comparable to or greater than other technologies
at a reasonable cost, but only limited data exist with which to evaluate
the performance record of the processes.
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Comment: The commenter (IV-D-27) suggested that provisions be made
in the standards to allow for decreases in the required recovery
efficiency to 85 percent of the original requirements as throughput at a
gas plant declines. He stated that declines in throughput for plants
are inevitable, although timing of the decline may be delayed if new
sources of gas are found. According to the commenter, plants experience
problems achieving design efficiency when throughputs are below 50 percent
of design; problems in achieving design efficiency become acute at 20 to
30 percent of design capacity. At 20 to 30 percent of capacity, the
volume to surface area ratios degrade, control devices are oversized,
and blowers must be turned down to inefficient values.
Comment: The commenter (IV-D-18) recommended that facilities
operating at less than 50 percent of design capacity be exempt from the
sulfur emission reduction efficiency requirements of §60.642.
The commenter also stated that natural gas processing facilities
handle varying quantities of gas with different compositions over a
period of time. Because of these fluctuations, the commenter recommended
that compliance with the standard not be required if the composition of
the gas or throughput changes are beyond the control of the owner or
operator and such changes cannot be reasonably accommodated by the
existing equipment.
Comment: The commenter (IV-D-29) suggested that plants operating
at less than 50 percent of design capacity and at less than 20 LT/D
throughput be exempted from the standards because of engineering problems
that occur when plants operate at less than 50 percent of capacity. The
commenter provided a case history of a 3-stage Claus plant designed with
a 27 LT/D capacity. He stated that the capacity was based on limited
production testing of shut-in gas wells that were expected to have
relatively high H2S concentration. The various gas lines supplying the
plant contained 25 to 25,000 ppm H2S and contained both sweet and sour
gas. The commenter reported that the plant start-up was unsuccessful
because the H2S concentration and flow rates at the plant inlet would
not sustain the thermodynamic requirements of the Claus catalyst bed
regeneration process. About $275,000 was spent to downsize the plant to
15.6 LT/D. The plant started up processing seven sour gas streams that
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could deliver 11.35 LT/D of sulfur. One well comprised 3.77 LT/D of
this total. Future connections are projected to supply 2.8 LT/D of
sulfur. Continuous operation of at least one of the three major H2S
producing wells is considered critical to a turned down operation of the
plant at 7 LT/D. He reported that further turndown would require another
modification of the plant.
Comment: The commenter (IV-D-29) claimed that the economic structure
on which the standard is based is in error because the difficulty of
maintaining stable operation when the plant is operating at less than
50 percent of capacity is not considered. The commenter stated that
operation at less than 50 percent of design capacity is a common occurrence
as aging gas fields decline in production or in new fields where production
has not reached peak levels. The commenter stated that during such
times, equipment is oversized for throughput and the reactions that
should take place are not complete. He further stated that these problems
are beyond the control of the plant operator unless the plant is designed
as a multitrain plant so that operation may be discontinued in stages as
field gas production declines. He stated that the concept of multitrain
design was not discussed in the Volume I BID or preamble. The commenter
claimed that the standard would force operators to use the multitrain
design to comply with sulfur recovery efficiencies.
Response: The required recovery efficiency, "Z," is based on the
sulfur feed rate and H2S concentration in the acid gas stream. Because
the required recovery efficiency is a function of these factors, as the
sulfur feed rate or H2S concentration decreases, the recovery efficiency
also decreases. Thus, the recovery efficiency equation at least partially
accommodates declines in gas throughput.
In response to these and other similar comments, the Agency discussed
the effect of decreased throughput on recovery efficiency with
Ralph M. Parsons Company, an engineer design firm with expertise in
sulfur recovery facilities (Docket Entry II-D-58 and IV-E-1). Information
received from this firm indicates that a three-to-one turndown is
attainable with standard instrumentation. A five-to-one or even
seven-to-one turndown can be attained with additional instrumentation
(e.g., dual control valves, dual metering, dual transmitters). Further,
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plants operated within their design operating ranges will achieve the
design recovery efficiency regardless of capacity utilization. Based on
these discussions, the Agency concluded that recovery efficiencies are
not adversely affected by decreases in throughput to levels well below
design capacity. As long as the proper H2S to S02 ratio is maintained,
design recovery efficiencies will not decline. The H2S/S02 ratio can be
maintained during periods of low throughput by modifying the supply of
process air to the combustion zone. With the maintenance of an
appropriate flow rate of the process air stream relative to the acid gas
stream, stoichiometric concentrations of H2S and S02 are attained and
sulfur recovery efficiencies are maximized.
The installed costs of instruments vary from about 5 percent to
10 percent of the total plant costs. These instruments will usually
allow good operation down to 33 percent of plant design rate. In order
to allow operation down to 20 percent of the plant design rate, an
additional instrumentation cost of 2 to 5 percent of the total plant
cost can be expected (Docket Entry IV-E-1).
Based on the information received from the Parsons firm, it is
apparent that proper instrumentation is the key factor in maintaining
appropriate recovery efficiencies during periods of decreased throughput.
The costs associated with this instrumentation (i.e., 5 to 10 percent of
total plant costs) appear to be within the range of the commenter's
expenditures for turndown modification.
Given the availability of technology and instrumentation to
accommodate load changes, turndown within the design range should not
affect the facilities' ability to achieve the required efficiency. The
Agency concludes that facilities experiencing such fluctuations are
expected to meet the requirements of the standards.
It should also be noted that plants with sulfur feed rates S5 LT/D
are required to meet the lower end of the range of efficiency achievable
by BDT for facilities of this size. This requirement accommodates
potential process operating difficulties that may occur in small plants.
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2.5 SELECTION OF MODEL PLANTS
Comment: One commenter (IV-F-4) questioned the assignment of 15 of
the total 21 model plants as plants with capacities not greater than
5 LT/D. In his opinion, a more appropriate distribution would include a
higher proportion of larger plants.
Response: The distribution of model plants selected was not intended
to mirror the distribution of existing or future plants, but rather to
facilitate the evaluation of various regulatory alternatives. The
distribution of model plants included plants with capacities of less
than 5 to more than 1,000 LT/D. Because potential adverse cost impacts
are more likely for plants of less than 5 LT/D capacity (i.e., small
plants), additional model plant cases in the small size range out of a
total of 21 model plants allowed more thorough evaluation of small plant
cost impacts.
Comment: The commenter (IV-D-13) questioned the use of 1982
production data as a basis for projecting the distribution of H2S
concentrations in future sour gas discoveries and the sizes of new
facilities. The commenter claimed that as shallow reserves are depleted,
new wells will be drilled deeper and that gas in those wells would be
likely to have higher H2S concentrations. In addition, the commenter
stated that future plants will also likely be larger sized plants, even
greater than 1,000 LT/D, because the new plants would have to be larger
to be economically feasible. The commenter requested that these ideas
be incorporated into development of the standards and stated that these
trends indicate that only larger plants should be subject to the proposed
standards.
Response: The Agency is aware of the trend toward development of
deeper, more sour wells through discussions with industry representatives
(Reference Docket Entry II-E-22). The trend toward higher H2S concen-
trations has been quantified based on the limited amount of available
data (see BID, Table 9-22) and considered in projecting the numbers of
facilities to be constructed. However, quantification of this trend
with respect to the size distribution of future facilities is not possible
because there are insufficient data available on how H2S concentration
affects plant size. For this reason, the trend toward deeper, more sour
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wells could not be incorporated in the approach to projecting sizes of
facilities to be affected by the standards. As the commenter suggests,
the facility projections may overpredict the number of small plants and
underpredict the number of large plants. Even if this is true, the
trend would not adversely affect the conclusions of the cost and economic
impact analyses.
Because economics of scale are possible with larger plants, they
incur proportionately smaller cost impacts. Similarly, larger plants
are less likely to incur adverse economic impacts. These facts show
that the approach taken in projecting sizes of affected facilities
probably overpredicts any potential adverse cost and economic impacts
that could result from the standards.
Regarding the commenter1s conclusion that only larger plants should
be subject to the standards because of this trend toward larger plants,
the standards are written to address the complete range of sizes that
may be constructed. Whether or not facilities of a particular size
actually are constructed cannot be predicted with certainty. The
standards should and will require application of BDT for any size plants
for which controls can be employed with acceptable economic impacts and
cost effectiveness.
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2.6 ECONOMIC IMPACT ANALYSIS
Comment: The commenter (IV-F-1) questioned the conclusion drawn in
the economic impact analysis (Chapter 9, BID) that no plant closings are
predicted under Regulatory Alternatives I through IV. This comment is
based on alleged errors made by EPA in calculating the real cost of
capital (BID, Section 9.2.1.1, pg. 9-60), and estimation of gas sales
revenues (BID, Table 9-28, pg. 9-62). Specifically, the cost of capital
was given as 0.019 (derived by the formula 1-discount rate/inflation
rate); the value, using EPA's discount rate and inflation rate, would
be -0.019. The commenter stated that since this incorrect cost of
capital was used to calculate annualized costs, those costs are in
error.
Secondly, the commenter stated that the use of an H2S/C02 ratio of
12.5/87.5 percent in the economic analysis for model plants with less
than 5 LT/D capacity overstates estimated revenues from gas sales and
results in inaccurate emission control costs per MCF of sales gas. The
commenter believed that ultimately these differences would indicate an
increased potential for plant closings.
Response: The commenter is correct in noting that an error was
made in the BID, Chapter 9, Section 9.2.1.1, page 9-60. The error was
not in the calculation of the real cost of capital but in the presentation
of the equation. The equation should read:
Real cost of capital = (1 + discount rate)/(l + inflation rate) - 1.
The assumed discount rate was 10 percent and the inflation rate was
8 percent, therefore, the real cost of capital was .019, and that cost
was used to calculate annualized costs.
Based on new information provided by the Gas Processors Association
survey (August 1983) (see Docket Entry II-D-59), the economic impacts of
the proposed NSPS have been reanalyzed. In the current analysis, a real
interest rate or real industry cost of capital of 6 percent is used.
This is calculated assuming a nominal interest rate of 11 percent (based
on the current prime rate) and an inflation rate of 5 percent. In
comparison to the 2 percent cost of capital used in the previous economic
analysis, the current analysis assumes a much higher cost of capital
reflecting the greater risk inherent in investments in the oil and gas
industry.
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In regard to the commenter's concern over the use of a 12.5/87.5 acid
gas ratio for less than 5 LT/D model plants in estimating revenues from
sales gas, the appropriateness of the acid gas ratio assumption must be
considered in light of the assumed H2S concentration in the sour natural
gas and the range of model plant sizes (i.e., LT/D sulfur feed) to which
the assumptions apply. The economic analysis considered H2S concentra-
tions in the sour gas ranging from 0.5 to 20 percent, model plant sizes
ranging from 0.1 to 1,000 LT/D sulfur feed rate, and a single acid gas
ratio of 12.5/87.5. The 12.5/87.5 acid gas ratio assumption is
appropriate given that it applies to the entire range of H2S concentra-
tions in the sour gas and model plant sizes considered in the original
analysis. However, as the commenter points out, acid gas ratios less
than 12.5/87.5 are more frequently encountered in the less than 5 LT/D
plants. Also, the percent H2S in the sour gas for plants less than
5 LT/D more commonly is in the 0.1 to 0.5 percent range, rather than the
0.5 to 20 percent range considered in the original analysis.
Since proposal, an expanded economic analysis has been conducted
(see Appendix A) that addresses the commenter's concern. In this expanded
analysis, acid gas ratios of 2/98, 5/95, 12.5/87.5, 20/80, 50/50,
and 80/20 and H2S concentrations in the sour gas ranging from 0.1 to
9 percent were evaluated for plants in the less than 5 LT/D size range.
Revenues from sweet gas sales for cases evaluated in the revised analysis
cover the complete range that can reasonably be expected at small
facilities. However, contrary to the concern raised by the commenter,
the revised analysis does not identify adverse economic impacts (i.e.,
plant closings) on facilities expected to be constructed in the future.
Comment: Commenter IV-F-5 cited the potential for adverse economic
impacts on nonmajor operators. He referenced an Oil and Gas Journal
(July 18, 1983, pg. 89) report which stated that nonmajor operators
account for 53 percent of all gas plants.
Response: The commenter has not provided any data on adverse
economic impacts for nonmajor operators. The revised economic impact
analysis conducted by the Agency indicates that Regulatory Alternative III,
upon which the standards are based, will not force the cancellation or
postponement of construction of projected onshore gas processing
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facilities. Consequently, shifts in output levels would be expected to
be very slight and would not encourage higher gas prices, or any other
disruption of the natural gas processing industry. Of the approximately
1,000 cases analyzed, 24 cases showed adverse economic impacts due to
the NSPS (see Appendix A). However, the cumulative probability of
facilities with the combinations of gas characteristics (represented by
these 27 cases) being built in the near future is only about 1 percent.
For this reason, the Agency believes that there will be no adverse
economic impacts as a result of the NSPS.
Comment: The commenter (IV-D-8) stated that, based on operating
experience at his facilities during 1978 through 1983, sulfur recovery
facilities have operated at approximately 34 percent of capacity. The
commenter stated that these plants once operated at 100 percent capacity,
but all plants eventually experience such a decline as a function of
field life. His concern is that the cost analysis performed by EPA on
the model plants assumed 100 percent operating capacity and that this
may affect the conclusions of the analysis. In subsequent discussions
with the commenter (Reference Docket Entry IV-D-14), the commenter
stated his concern that the entire economic analysis should take into
account the fact that despite the decline in volumes, producers try to
maximize production and as producing fields age, production declines.
Response: The commenter's concern about production decline as it
relates to the cost analysis is addressed in Section 2.7. His concern
about production decline as it relates to the economic analysis has been
considered in a revised analysis presented in Appendix A. The revised
analysis assumes that capacity utilization averages 75 percent over the
life of the facility. (Selection of this factor is discussed in
Section 2.7.) The amount of sweet gas and sulfur for sale are each
calculated based on 75 percent capacity utilization. As the results of
the revised economic impact analysis show, even when production declines
are taken into consideration, the NSPS does not impose adverse economic
impacts on plants likely to be built in the future. The probabilities
of different size plants with different gas characteristics being built
in the future were calculated. These probabilities were based on
historical size and gas characteristic data. The potential economic
impacts on each of these cases were estimated. Out of the approximately
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1,000 cases examined, 27 showed significant adverse impacts due to the
NSPS. However, the cumulative probability of a facility with charac-
teristics similar to any of these cases being constructed during the
next 10 years is only about 1 percent. Therefore, EPA's conclusion
based on the economic impact analysis is that the NSPS will not impose
unreasonable economic impacts on any plants likely to be built in the
future.
Comment: The commenter (IV-D-19) states the combined effects of
the assumptions used in the economic impact analysis (Chapter 9, BID)
lead to an underprediction of the number of unprofitable plants that
will result from the standard and incorrect conclusions regarding
negligible economic impacts resulting from the standard. He asserts
that a minimum of 12 percent cost of capital should be used rather than
the 10 percent rate assumed in EPA's analysis, and further, that a
12-year equipment life rather than 20 years should be assumed based on
the 12-year average small field life reported in a Gas Processors
Association (GPA) survey (Docket Entry II-D-59). Moreover, he states
that a maximum $3.20/MCF (1980 dollars) price of of natural gas in 1987
is a more accurate prediction than the $4.80/MCF (1980 dollars) value
assumed in the Agency's analysis.
The commenter also states that the cost of sour gas treating (i.e.,
sweetening) is not included in the production costs considered in the
economic impact analysis (BID, Table 9-4).
The combined effects of the higher sulfur recovery costs, the added
production cost for sweetening, and the lower revenues from sale of
sweet gas at $3.20/MCF, justify, in the commenter1s mind, a small plant
exemption limit of no less than 5 LT/D sulfur feed rate. Further, the
commenter suggests an exemption limit of 10 LT/D to ensure that there
would be no unprofitable plants in the short run.
Response: The commenter states that a 12 percent cost of capital
should be used. The commenter provides no basis for this number. The
current economic impact analysis assumes an 11 percent nominal cost of
capital based on the current prime rate which converts to a 6 percent
real cost of capital assuming a 5 percent inflation rate. The revised
economic impact analysis, based on the Gas Processors Association survey,
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reflects a 12-year well life for plants with sulfur feed rates less than
or equal to 20 LT/D and a well life of 20 years for plants with feed
rates greater than 20 LT/D.
The commenter suggests a 1987 natural gas price of $3.20/MCF
(1980 dollars). The current economic analysis is conducted in 1984
dollars. The natural gas prices for each year of this analysis are as
follows:
(1984 $/MCF)
1985 $3.88
1986 4.06
1987 4.25
1988 4.44
1989 4.64
1990 4.86
1991 5.08
1992 5.32
1993 5.56
1994 5.82
These prices are projected national average wellhead prices for new
natural gas. The prices were generated from the hydrocarbon supply
model developed by Energy and Environmental Analysis, Inc. and referenced
in their July 1984 report entitled "Regional Forecasts of Industrial
Residual Fuel Oil and Natural Gas Prices" (Docket Entry IV-A-4). The
prices assume natural gas deregulation in 1985. For purposes of
comparison, the 1987 price of $3.20/MCF in 1980 dollars suggested by the
commenter converts to $4.73/MCF in 1984 dollars. As noted above, the
Agency has used a more conservative 1987 price of $4.25. (Conversion
factor is 1.477 using the product price index for gas fuels for July 1984
of 1123.5 [Monthly Labor Review, 11/1984. pg. 90, U.S. Department of
Labor, Bureau of Labor Statistics (Docket Entry IV-J-4)] and the product
price index for gas fuels for 1980 of 760.6 [Statistical Abstract of the
U.S., 1981, pg. 462, Table 773, U.S. Department of Commerce, Bureau of
the Census (Docket Entry IV-J-2)].)
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The commenter correctly notes that the costs of sweetening were
erroneously excluded in the previous analysis. The sweetening costs
have been included in the current analysis. The results of the current
economic analysis (see Appendix A) do not justify a small plant exemption
any higher than 1 LT/D.
Comment: The commenter (IV-D-25) stated that if the proposed
standards are approved, the "one" sour gas well in a "sweet" gas field
would have to be capped and not produced because it would be uneconomical
to install sulfur removal equipment. He states that the standard should
be withdrawn because the forcing of uneconomical gas plants will result
in marginal gas plants not being constructed and usable natural gas not
being produced.
Response: The revised economic impact analysis shows that for
those plants likely to be built in the future, the promulgation of the
NSPS will not make any projected plants that are economical in the
baseline uneconomical under the NSPS. Theoretically, some plants with
high percentages of H2S in the sour gas, if built, would be uneconomical
under the regulation. It should be noted, however, that the cumulative
probability of facilites with these particular gas characteristics being
built in the near future is only about 1 percent. (See Appendix A for a
presentation of the probability tables.)
Comment: Commenter IV-D-29 cited in evidence of the economic and
operating drawbacks of small sulfur plants, the lack of existing petroleum
extraction industry sulfur recovery plants in the small plant size range
(BID, Table 9-7, Appendix G). Further, he alleged that the sweetening
facility sulfur production capacity date in the BID, Table 9-6, shows
that economics justify only sweetening plants in the small plant size
range.
Response: The revised economic impact analysis shows that there is
no economic justification for a small plant cutoff below 1 LT/D. Those
plants greater than 1 LT/D likely to be built in the future, that are
economical in the baseline, remain economical under the NSPS. The cases
that do not maintain profitability under the NSPS have very low (about
1 percent) cumulative probability of being built in the near future due
to the combinations of H2S in the acid gas and in the sour gas. Thus,
from a national perspective, the Agency is not imposing significant
adverse economic impacts on the industry.
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Comment: Two commenters (IV-D-18 and IV-D-29) expressed concern
that the increased sulfur recovery resulting from the NSPS would result
in a reduction in the price of sulfur. Commenter IV-D-29 stated that if
a gas/sulfur plant is a break-even operation, at start-up, a decrease in
sulfur price could force the plant to close.
Commenter IV-D-22 also requested that the Agency consider the
limited number of locations available for the sale of sulfur in
determining revenues from sulfur recovery. The commenter claimed that
the limited sales locations could increase transportation costs to the
point where they exceed or offset all sale credits.
Response: The additional amount of sulfur that would be available
for sale as a result of the NSPS is about 25,000 metric tons in the
fifth year after the standards are in effect (1990). The total domestic
sulfur supply in 1980 (Figure 9-3 of the BID for the proposed standards)
was approximately 12.5 million metric tons. Approximately 2.5 million
metric tons of sulfur were imported. Based only on the domestic
production figure, the increase in recovered sulfur as a result of the
NSPS represents only about 0.2 percent of the 1980 domestic sulfur
market. Thus, the impact of the NSPS on the sulfur market is expected
to be minimal. It should be noted that Frasch mine production, which
represents almost half of the domestic production, has been declining
steadily since 1968.
Refer to Section 2.7 for a discussion of transportation costs
involved in the sale of recovered sulfur.
Comment: The commenter (IV-D-29) claimed that the Agency relied on
a faulty assessment of the economics of sulfur recovery in justifying
the 1 LT/D cutoff limit for affected facilities. He states that sulfur
recovery at low throughput is not economically attractive or desirable
and that the 1 LT/D exemption limit is below a throughput that would
sustain the capital and operating cost of a stand-alone sulfur recovery
plant. In his opinion, the economics of the sulfur plant should be
considered irrespective of revenues from sweet gas sales. He stated
that the economic basis for justifying the cutoff in the proposed
standards was faulty because it considered revenues from natural gas
sales in determining the profitability for sulfur recovery plants.
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The commenter stated that the rationale for setting the 20 LT/D
cutoff in the NSPS for refinery sulfur plants was based on the economic
recovery of sulfur in dollars per long ton. In his view, the approach
taken for the natural gas processing 1 LT/D cutoff is analogous to
establishing the refinery NSPS cutoff at the level where total oil
throughput sustains sulfur recovery costs. He alleged that EPA rejected
this approach because of impacts on small refineries. He claimed that
the Agency should be consistent and give the same consideration to gas
plants since 53 percent of gas plants are owned and operated by businesses
other than major oil companies (Reference: Oil and Gas Journal, July 18,
1983, pgs. 90 to 121).
Response: In regard to the commenter's statement that the 1 LT/D
cutoff is below a throughput that would sustain the costs of a sulfur
recovery plant and that the economics of a sulfur plant should be
considered irrespective of revenues from sweet gas sales, the Agency
believes that it is appropriate to consider revenues from sweet gas
sales in determining the profitability of sour gas processing facilities.
The intent of the Agency in promulgating this NSPS is to reduce SOa
emissions from all new natural gas processing facilities where BDT can
be applied without resulting in adverse economic impacts (e.g., plant
closings) and without resulting in an unreasonable cost effectiveness
(i.e., costs per ton of emission reduction). In determining the
profitability of sour gas plants, the Agency appropriately analyzed the
effect that the control costs would have on the companies' revenues,
which are derived primarily from the sale of sweet gas and in some
cases, from the additional sale of recovered sulfur. (It should be
noted that revenue from the sale of recovered sulfur was not assumed in
the economic impact analysis for plants with sulfur feed rates below
5 LT/D. Projected plants with sulfur feed rates below 5 LT/D were shown
to be profitable without the additional sale of recovered sulfur.)
Since the purpose of sour gas processing facilities is primarily to
produce and sell sweet gas, profitability of sour gas processing
facilities is appropriately based on revenues from the sale of product
(i.e., sweet gas) as well as the sale of recovered sulfur.
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The exemption in the refinery NSPS for sulfur plants with less than
20 LT/D capacity is unlike the exemption in these standards in that it
represents an exemption from tail gas treatment requirements (i.e., it
is not an exemption from sulfur recovery requirements). Furthermore, in
its 4-year review of the refinery NSPS, EPA considered lowering the
20 LT/D cutoff, based on cost-effectiveness. The reason that the cutoff
was not lowered was because refinery sulfur recovery plants with feed
rates less than 20 LT/D represent a very small fraction of projected
growth in capacity (48 FR 57239, December 28, 1983). Cost effectiveness
was also a major consideration in determining the cutoff for the standards
for natural gas processing plants. The highest incremental cost effective-
ness (in dollars per metric ton of S02 emissions reduced) of these
standards would be about $925/Mg. This is the incremental cost
effectiveness for a plant with a sulfur feed rate of 555 LT/D, compared to
the baseline. This cost effectiveness is considered to be reasonable by
the Agency; consequently, there is no basis for exempting plants with
sulfur feed rates £2 LT/D.
Comment: The commenter (IV-D-13) believes that the economic analysis
supporting the proposed rule and documented in Chapter 9 of the BID
should consider the incremental costs compared to the additional sulfur
removal. The commenter suggested that costs of increased monitoring,
maintenance, recordkeeping, and performance testing should be compared
to any increased sulfur recovery rather than gross revenue generated by
sales of sour gas. The commenter further stated that although emission
controls are considered by industry in evaluating new projects, regulatory
action to require additional controls should be evaluated in relation to
the base case, which is processing of gas under current regulations.
The commenter further stated that projected normal costs in the economic
impact analysis (Chapter 9, BID) were incorrect because they did not
include the possibility of increased income and severance taxes.
Response: The incremental cost effectiveness of the regulation
compared to less stringent control options was the most important
consideration in selecting the regulatory alternative on which the
standards are based (see preamble to the proposed standards, 49 FR 2660).
Incremental cost effectiveness was also the factor used in setting the
small plant exemption. The increased costs of the regulation, including
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increased monitoring and maintenance costs, were evaluated in light of
the increased S02 emission reduction that would be achieved. The highest
incremental cost effectiveness under the regulation would be $925/Mg, a
figure judged by the Administrator to be reasonable. [Plants that would
spend more than that amount per Mg of additional emission reduction
(i.e., plants with sulfur feed rates <2 LT/D) have been exempted from
the standards.]
In addition to considering cost effectiveness, the Agency also
analyzed the economic impacts of the standards on approximately
1,000 cases. These cases included plants within a wide range of sulfur
feed rates and with numerous combinations of percent H2S in the sour gas
and H2S-to-C02 ratios in the acid gas. The results of this analysis
indicate that none of the plants that are likely to be built and that
would be covered by the NSPS would experience significant adverse economic
impacts. The Agency's economic analysis was based on total control
costs and their impact on plant profitability, taking into consideration
the revenues from the sale of sweet gas. The reason why the Agency
believes that it is appropriate to consider such revenues is described
in the response to the previous comment.
The economic impact analysis considered neither the possible increase
nor possible decrease in income tax but rather assumed a 50 percent tax
rate for the entire time period of the analysis. In response to the
commenter's concern over the potential for increased severance taxes, an
investigation was made into the magnitude of taxes currently levied on
typical natural gas producers. The results showed that the nature and
magnitude of natural gas production taxes vary widely from location to
location and from production facility to production facility (see Docket
Entry IV-B-9). However, in most every State where sour natural gas is
produced, some type of production rate tax, or severance tax, is assessed
on the producer. Tax rates currently levied by the States contacted
ranged between about 1 and 10 percent. To account for these taxes, a
typical value of 5 percent was factored into the revised economic impact
analysis described in Appendix A. Although severance taxes may be
increased in some States to provide additional revenue sources, such
increases are very difficult to predict. However, any increase would
not be expected to affect the overall results of the economic impact
analysis.
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2.7 COST-EFFECTIVENESS ANALYSIS
Comment A: The commenter (IV-F-1) stated that because an API
survey showed an average operating rate of 75 percent of design capacity,
different from the value of 100 percent used in the proposed standards,
the dollar per ton S02 removal costs in the proposed standard should be
increased 33 percent.
Comment B: The commenter (IV-D-8) stated that, based on operating
experience at his facilities during 1978 through 1983, sulfur recovery
facilities have operated at approximately 34 percent of capacity. The
commenter stated that these plants once operated at 100 percent capacity,
but all plants eventually experience such a decline as a function of
field life. His concern is that the cost analysis performed by EPA on
the model plants assumed 100 percent operating capacity and that this
may affect the conclusions of the analysis. In subsequent discussions
with the commenter (Reference Docket Entry IV-D-14), the commenter
stated his concern that the entire economic analysis should take into
account the fact that despite the decline in volumes, producers try to
maximize production and as producing fields age, production declines.
Response: In response to comments, the Agency reviewed the capacity
utilization assumption. Commenter B was contacted to determine the age
of his gas processing facilities and it was learned that the facilities
were at least 23 to 30 years old during the period in which the 34 percent
capacity utilization was reported.
An analysis of the available data indicates that average capacity
utilization is typically closer to 75 percent. Consequently, the Agency
has accepted Commenter A's 75 percent capacity utilization factor and
has recalculated the cost effectiveness of the standards. The results
of the revised cost-effectiveness analysis affect plant size applicability.
The 75 percent capacity utilization assumption was also incorporated
into the revised economic impact analysis. The amount of sweet gas and
sulfur for sale were each calculated based on 75 percent capacity
utilization. The results of the revised economic impact analysis show,
even when production declines are taken into consideration, the standards
do not impose adverse economic impacts on plants likely to be built in
the future.
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Assuming a 75 percent capacity factor, the calculated incremental
cost effectiveness (ICE) for Alternative III over Alternative II for
model plants ^4 LT/D is as follows:
Model
plant
size
(LT/D)
1
2
3
4
A
ICE based
on 100%
capacity
($/Mg S02)
1,030
642
487
408
B
ICE based
on 75% .
capacity
($/Mg S02)
1,393
840
652
568
Increase of
B over A
35%
31%
34%
39%
Reference BID Table 8-8.
Reference Docket Entry IV-B-6.
The revised analysis incorporated assumptions used in the calculation
of ICE for the proposed standards (Docket Entry II-B-44) except:
• 75 percent capacity utilization was used instead of 100 percent,
• a 12-year equipment life (and thus capital amortization period)
was used instead of a 20-year life, and
• stack monitoring requirements were eliminated, therefore,
monitoring costs were reduced by $39,700/yr (i.e., the stack
monitoring costs).
Based on cost-effectiveness considerations, the standards have been
revised to exempt facilities with sulfur feed rates less than 2.0 LT/D.
Comment: The commenter (IV-D-7) stated that the Michigan State Air
Quality Division investigated available control technologies for
sweetening units and concluded that control of S02 is economically
feasible for most units except for very small plants, i.e., less than
0.1 LT/D sulfur equivalent. The commenter provided copies of the data
and noted that different technologies were required for plants handling
low- and high-pressure gas. The commenter stated that the decisions on
economic feasibility were based on the criterion of cost per 1,000 cubic
feet of gas instead of the cost per megagram of S02 controlled criterion
as considered by EPA. The commenter recommended that EPA use this
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approach in cost analysis because the cost per ton S02 removed may not
truly reflect the affordability of the control technology.
Response: The Agency agrees with the commenter that the criterion
for economic affordability should be cost per MCF of gas and not cost
per Mg of S02 controlled. The economic impact analyses, both the original
preproposal analysis and the revised analysis, did evaluate affordability
on the basis of costs per MCF of gas, not on the basis of costs per Mg
of S02 as stated by the commenter. The revised analysis indicates that
S02 controls are affordable by all projected plants without adverse
economic impacts. However, even though S02 control may be affordable by
plants with sulfur feed rates <2 LT/D, these plants would typically
spend more than $l,000/ton of S02 removed. In the Administrator's
judgment, these costs would be unreasonably high for S02 control at
natural gas processing plants. It is for this reason, rather than
affordability, that plants with sulfur feed rates <2 LT/D are exempt
from control requirements of the standards.
During the 4-year review of the standards, the Agency will evaluate
additional technologies (e.g., caustic scrubbers). If new technologies
with reasonable cost-effectiveness are available for smaller plants, the
Agency may lower the plant size cutoff.
Comment: The commenter (IV-D-8) is concerned that the cost and
technology assumptions made in the model plant/control technology
alternative approach to selecting a standard do not represent present or
future design conditions at representative natural gas processing plants.
The commenter indicated that the five sour gas processing plants operated
by his company have standard plant designs, which specify oxidation of
all sulfur compounds in acid gas or tail gas streams released to the
atmosphere. The commenter was concerned that incineration costs should
be considered in the analyses supporting the standard.
Response: The Agency recognizes that incineration costs are a
necessary constituent of baseline control costs (i.e., costs incurred in
the absence of the NSPS). The appropriate place for consideration of
incineration costs is in the economic impact analysis which considers
total costs to the plant (i.e., baseline costs and the additional costs
necessary to meet the NSPS), and baseline incineration costs were included
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in the revised economic impact analysis. Since incineration costs are,
however, part of baseline costs, they are not considered in the
incremental cost-effectiveness analysis.
Comment: The commenter (IV-D-13) claimed that the projected costs,
including plant and engineering overhead as well as maintenance costs
are greatly underestimated. No cost data were included with the comment.
Response: The cost derivation for 5 to 1,000 LT/D plants and
plants with capacities less than 5 LT/D (BID, Chapter 8 and Appendices E
and H) were based on data from studies conducted by a sulfur recovery
equipment vendor (Docket Entries II-A-16 and II-A-20). Step-by-step
sample calculations for converting these data to annualized costs are
given in Docket Entries II-B-29 and II-B-44. Efforts were made to
include all associated costs components and to make the estimates
representative of actual facility costs. As a check, total cost data
provided by industry for three actual natural gas processing plants were
compared to the estimated costs for similar facility types (Docket
Entries II-A-16 and II-A-20). Although exact comparisons could not be
made because of differences in the actual plant characteristics and the
model plant characteristics, the comparison provided a general indication
that the cost estimates were representative of actual costs.
Comment A: Commenters IV-D-27 and IV-D-29 claimed that the Agency
overestimated the price of sulfur in calculating sulfur revenues.
Commenter IV-D-18 stated that the market available for recovered sulfur
and the price at which it can be sold need to be reexamined.
Commenter IV-D-27 stated that the sales price per ton is seldom the
price received by the gas processing plant and, for example, after
transportation cost payments, the net back to a plant in Texas may be
$30 to $40 per ton less than the sales price and for a plant in Wyoming,
the net back may be another $40 to $45 lower. Commenter IV-D-29 claimed
that the posted price of sulfur has steadily decreased to $132/LT in
July 1983 (C&E News, 1983) and that the posted price and selling price
are different. For example, the December 1983 selling price for Eustace,
Texas liquid sulfur (f.o.b. Tampa, Florida) was $80/LT which netted the
operator about $50/LT.
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Comment B: The commenter (IV-D-18) agrees with the Agency's
assumption in the cost-effectiveness analysis (Chapter 8, BID) that
small plants will dispose of rather than sell recovered sulfur and that
sulfur disposal costs (and no sulfur credits) will be incurred. However,
he believes this assumption should apply to plants up to 20 LT/D of
sulfur throughput rather than 5 LT/D as assumed by the Agency.
Response: In response to comments A and B regarding prices received
by gas processing plants for recovered sulfur, the Agency contacted
several industry representatives and personnel involved in commodity
price trends (Docket Entry IV-B-3). According to data obtained from the
U.S. Bureau of Mines, the prices paid for recovered sulfur in 1983
ranged from $36/LT to recoverers in the Rocky Mountain areas to $117/LT
to recoverers in the Gulf Cost area. The average 1983 f.o.b-plant price
paid to recovered sulfur suppliers was $77/LT. From 1979 to 1983 the
average f.o.b-plant prices ranged from $49/LT to $100/LT. The results
of a survey of natural gas processing plant operators substantiate the
Bureau of Mines information. The respondents cited a range of $40/LT to
$100/LT received for recovered sulfur. The Agency is aware that posted
prices and selling prices are different and that transportation costs
vary according to distances from terminals. For sellers of recovered
sulfur, transportation costs are generally incurred on a negotiated
basis with shipper/transporter agreements dependent on volume, distance,
and demand. These rates are regarded as "artificial" and are neither
predictable nor standard.
The Agency used $100/LT for recovered sulfur in the cost-effectiveness
analyses for the proposed standards. This value was based on information
which indicated that elemental sulfur prices increased over 337 percent,
from $31.49 per megagram in December 1969 to $137.79 per megagram in
March 1981 (BID Table 9-17). Although sulfur prices fluctuated during
this period, the trend demonstrated an increase on a consistent basis.
Based on the information received from the above sources, the
Agency has revised the assigned price for recovered sulfur from $100/LT
to $77/LT. This estimate takes into account transportation costs,
fluctuating sulfur prices, and the fact that prices paid for recovered
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sulfur are generally 10 to 17 percent lower than for mined sulfur. It
represents the average 1983 f.o.b-plant price paid to suppliers of
recovered sulfur and is consistent with estimates made by gas plant
operators.
During the survey of industry representatives regarding sulfur
prices, the Agency obtained information regarding recovered sulfur
selling/disposal practices with respect to plant size. Of the
seven respondents representing plants from 5-20 LT/D, all sold recovered
sulfur. Based on this information, the Agency is continuing with the
assumption that plants S5 LT/D generally sell recovered sulfur.
Comment: Commenters IV-D-18 and IV-D-29 questioned the Agency's
assumptions regarding the amount and H2S content of sour gas to be
developed and the number of new sweetening plants to be constructed.
The commenter (IV-D-29) claimed that EPA overestimated both sulfur
content and the percent volume of sour gas that would be treated in
sulfur recovery plants in the absence of the NSPS. Specifically, he
claimed that historical data (Docket Entry II-D-41) show that the portion
of sour gas currently treated for sulfur recovery is 31 percent; whereas
EPA assumed 75 percent of new sour gas would be treated for sulfur
recovery in the absence of the NSPS. Furthermore, the commenter believes
that the same historical data indicate that the concentration of H2S in
gas currently treated for sulfur recovery is 5.27 mole percent, rather
than the 5.8 number used by EPA.
While the commenter disagreed with the Agency's prediction that
75 percent of new sour gas will be treated for sulfur recovery, he
stated that if the Agency was going to assume 75 percent, then it should
predict sulfur content based on 75 percent of all the streams in the
commenter1 s survey data. Instead the Agency based its projection of
sulfur content on the weighted average H2S content of only those streams
that are currently treated for sulfur recovery. Using the commenter1s
approach, the Agency's estimate of 5.8 percent H2S would be reduced to
2.31 percent. Using the 2.31 number, total sulfur recovery capacity
would be 1,296 Mg/D instead of 3,244 Mg/D as projected in the BID
(Table 9-21).
The commenter claimed that the above differences indicated a need
to reevaluate the cost-effectiveness and economic impact analyses.
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Response: The EPA's projections of the amount of sour gas that
would be treated for sulfur recovery and of the sulfur content of that
gas were based on: 1) an analysis of data demonstrating the trend
toward higher H2S concentrations (Table 9-22 of the BID), 2) an analysis
of the July 1982 survey data provided by the commenter, and 3) discussions
with sulfur recovery equipment vendors and regulatory officials with
experience in the sour gas processing industry. These discussions
(Docket Entries II-D-23, 24, and 25) indicated that, under baseline
conditions, sulfur will be recovered from about 75 percent, by volume,
of the newly discovered sour gas that will require sweetening prior to
sale to pipeline companies. The other 25 percent will be sweetened but
will not be treated for sulfur recovery. This 75 percent estimate takes
into account the historical trend toward deeper wells with higher H2S
contents. Data in the BID illustrate this trend (see Table 9-22,
pg. 9-44). The estimated average H2S concentration has increased from
about 1-2 percent in the 1960's to 5-6 percent in the late 1980's. In
the baseline, decisions about whether or not to install sulfur recovery
equipment are driven largely by State regulations and economic incentives.
The expectation is that these incentives in conjunction with the trend
toward deeper, more sour wells will result in roughly 75 percent by
volume of new sour gas being subjected to sulfur recovery.
The 5.8 percent H2S number that the Agency used to predict the H2S
content of future sour gas that will be treated for sulfur recovery in
the baseline (i.e., in the absence of the NSPS) was derived from the gas
plant survey data provided by the commenter in July 1982 (BID, Appendix G).
The Agency calculated a weighted average percent H2S content for all the
streams in the survey that were identified as being treated for sulfur
recovery. According to this survey, decisions to employ sulfur recovery
equipment have, in the past, corresponded to an average H2S concentration
of 5.8 percent. The 5.8 percent value also was compared to the H2S
concentration data prepared in evaluating the trend toward deeper more
sour wells (BID, Table 9-22). These data support the 5.8 percent H2S
estimate and it is expected that, in the absence of the NSPS, decisions
to employ sulfur recovery will continue to be based on this same
concentration.
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The 5.27 percent H2S value suggested by the commenter is based on a
revised survey data set (Docket Entry II-D-41, October 29, 1982) that
was received by the Agency after the proposal BID had been prepared.
The Agency agrees that the revised data indicate that the 5.8 percent
number should be updated to 5.27 percent. While the difference between
the two numbers (about 10 percent) did not, in the Agency's opinion,
warrant revision to the proposal BID, the Agency did use the 5.27 percent
number in the analyses supporting the final standard.
The commenter's suggestion that the projected sulfur content of new
gas treated for sulfur recovery should be based on 75 percent of all the
gas streams in the API survey (if the Agency continues to use 75 percent)
would result in a significant understatement of the sulfur content. The
commenter's 2.31 percent H2S number implies that the H2S content of
future sour gas treated for sulfur recovery will mirror the H2S content
of all sour gas in the survey data which includes, primarily, gas streams
that are not currently treated for sulfur recovery. The 5.8 percent
number (now revised to 5.27) corresponds to the sulfur content of sour
gas that is currently treated for sulfur recovery because the purpose of
the number is to predict the sulfur content of sour gas that will be
treated for sulfur recovery in the future (in the baseline).
In summary, the Agency reviewed data that served as the basis for
the projections of the amount of sour gas that would be treated for
sulfur recovery and of the sulfur content of that gas. As stated earlier,
the Agency revised its projection of percent H2S concentration from
5.8 percent to 5.27 percent; however, the Agency believes that the other
assumptions and projections remain valid.
Comment: The commenter (IV-D-29) questioned the basis for the
statements in the preamble to the proposed regulation that the NSPS
represents a 78 percent reduction of S02 emissions from SIP levels and
that "a large potential for reduction in S02 emissions exists with the
projected growth" in the industry. He claimed that the economics and
existing State regulations have caused the petroleum extraction industry
to install more sulfur recovery capacity than that assumed by the Agency.
He claimed that API data show 94 percent of the sulfur in all onshore
sour natural gas was subject to sulfur recovery during 1981. Further,
he claimed that current PSD requirements for BACT are a marked reduction
from the SIP levels. Consequently, he feels EPA's baseline, Regulatory
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Alternative I is low, and he stated that this calls into question the
emission reduction benefits and cost analyses of Regulatory Alternatives II
through VI.
Response: In developing NSPS, baseline control levels are estimated
for the purpose of evaluating emission reduction and cost impacts. As
such, baseline control levels are intended to represent controls typically
required across the nation in the absence of NSPS. While it is true
that some States have required, for specific plants subject to PSD
requirements, higher levels of S02 control than the typical SIP level,
these requirements have been site-specific and thus are not considered
to be good indicators of typical nationwide control levels.
The commenter claimed that API data show that 94 percent of the
sulfur in all onshore sour gas was treated for sulfur recovery during 1981.
For comparison with this figure, the Agency estimated the percent of
sulfur assumed to be treated for sulfur recovery in the baseline. The
Agency projects a 5-year total sulfur recovery capacity of 3,244 Mg/D
(Table G-4 of the BID) and a total sweetening capacity without sulfur
recovery of 38.9 Mg/D (Table G-7 of the BID). Based on these numbers,
the Agency has projected that about 99 percent of the sulfur would be
treated for sulfur recovery in the baseline. Compared to the commenter's
94 percent figure, it would appear that the Agency did not underestimate
the level of control typically required in the baseline.
Comment: The commenter (IV-D-29) claimed that the Agency calculated
costs of $171 to $408,000/Mg S02 removed (BID, pgs. 8-17 and 8-19) but
did not directly use those costs in setting the plant size cutoff limit.
The commenter stated that actual incremental costs of sulfur recovery
are in the $1,030 to $9,840/LT range.
Response: The commenter references several cost per megagram of
S02 removed (cost effectiveness) figures from the BID and alleges that
the Agency did not directly use those costs in setting the plant size
"cutoff limit." As stated in the preamble to the proposed regulation,
the Agency did consider, among other factors, the incremental cost
effectiveness, or the ratio of the additional cost and the additional
emission reduction for one regulatory alternative compared to the next
more stringent alternative in selecting Regulatory Alternative III as
the basis of the standard. Because Regulatory Alternative III affects
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only sweetening units of £2 LT/D sulfur feed rate, it does implicitly
establish a "cutoff limit" as referred to by the commenter. Furthermore,
the model plant/control technology combinations making up the regulatory
alternatives maintain consistent incremental cost effectiveness and to
this extent, cost effectiveness values, including several values
referenced by the commenter, were used in setting a "cutoff limit."
The manner in which the commenter referred to the numbers from the
BID, however, indicate a misunderstanding of how those numbers relate to
the decisions made by the Agency. The $171/Mg value is the cost
effectiveness of the 2-stage Recycle Selectox process (Regulatory
Alternative III) compared to incineration (the baseline control) for a
5 LT/D plant. The $408,000/Mg value would be the incremental cost
effectiveness of a 3-stage Recycle Selectox process compared to a 2-stage
process for a <0.1 LT/D plant. Even the most stringent alternative
considered by the Agency did not include controls for any plants 0.1 LT/D
or smaller in size. Consequently, the $408,000/Mg incremental cost
effectiveness value was not pertinent to the selection of the basis for
the standard. Neither was any other model/plant control technology
combination resulting in an incremental cost effectiveness of greater
than $44,800/Mg pertinent to the final selection by the Agency. The
incremental cost effectiveness values that were considered in evaluating
the regulatory alternatives are listed in Table 8-8 of the BID (pg. 8-16).
Review of this table also shows that the commenter's allegation that
actual incremental costs of sulfur recovery are in the $1,030 to
$9,840 range is in error. The highest incremental cost effectiveness
resulting from Regulatory Alternative III, the selected basis for the
standard, is $l,030/Mg for a 1 LT/D plant size.
In response to comments on the proposed standards, the Agency
conducted a revised cost-effectiveness analysis incorporating updated
assumptions (see Section 2.7). The revised analysis shows that the
highest incremental cost effectiveness resulting from Regulatory
Alternative III is about $l,400/Mg for a 1 LT/D plant (Docket
Entry IV-B-6). However, the standards have been revised to exempt
plants <2 LT/D from the control requirements of the standards. The
incremental cost effectiveness for a plant with a sulfur feed rate of
2 LT/D is $840/Mg.
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2.8 SMALL PLANT EXEMPTION
Sulfur Intake Rate Cutoff
Several commenters recommended changing the 1 LT/D cutoff provision
specified in the proposed standards. Two commenters (IV-D-10 and IV-D-28)
suggested a 5 LT/D cutoff; six (IV-D-12, IV-D-16, IV-D-22, IV-D-27,
IV-D-30, and IV-D-31) suggested 10 LT/D; and seven (IV-F-1, IV-F-5,
IV-D-11, IV-D-13, IV-D-20, IV-D-23, and IV-D-29) proposed a 20 LT/D
cutoff. Commenter IV-D-18 recommended that plants less than 100 LT/D be
regulated less stringently. Various reasons for revising the cutoff
specification were cited and these are discussed below.
Comments: Commenter IV-F-3 stated that adopting a higher cutoff
would allow some plants with marginal economic success to continue gas
production and allow production of fields which might not otherwise be
produced (i.e., because of the standards as proposed). This commenter
and others (IV-D-12, IV-D-20, IV-D-23, and IV-D-29) stated that the
proposed standards could cause many small wells containing H2S to go
unproduced. Commenter IV-D-20 stated that the possibility of premature
abandonment of gas and sulfur recovery plants is greater for plants less
than 20 LT/D and that the effects of the discouragement of natural gas
production could contribute to supply disruptions. Commenter IV-D-31
stated that a sulfur plant may be required for as little as one or
two wells and the wells may be short-lived. Commenters IV-F-3, IV-D-18,
and IV-D-27 also reported that variability in well production affects
the economic viability of small plants. In addition, commenter IV-F-3
restated the need for the preamble to include more small plant economic
data, referred to the data on this subject submitted previously (by the
commenter) and urged other members of industry to submit additional
information. The commenter stated that he had provided supporting
documentation for recommending an exemption for plants with sulfur feed
rates less than 5 LT/D. Commenter IV-D-20 stated that because of the
high investment costs of sulfur recovery plants relative to the value of
sulfur and the lower costs of S02 emission reduction from other
industries, the 1 LT/D cutoff limit is unreasonable and inequitable.
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Response: The preamble to the proposed rule discussed the concerns
raised by some industry representatives that sweetening plants producing
acid gas with 5 LT/D or less of sulfur could experience unreasonable
economic impacts. These concerns mirror those of the commenters, which
identified variability in well or field production rates and other
factors influencing the economics of small plants. The Agency understands
the commenters1 concerns regarding "variability in well production" to
mean that the economic life of a particular facility may be less than
the 12-year average life assumed in the standards. The 12-year life
assumption is based on an industry survey of small plants (Docket
Entry II-D-59) that indicated the average life of plants ^20 LT/D is
12 years. Subsequent economic analyses, using a facility life of
12 years, showed no adverse impacts.
The data submitted previously by the commenter (IV-F-3) (Docket
Entry II-E-40) concerning economics of small plants provided some insight
into the methods of economic analysis used by natural gas producers, but
was not specific enough to indicate the exact economic criteria used in
the decision-making process for proceeding with well development. For
example, the commenter provided data concerning the cumulative percent
of total wells vs. reserves. Although these data serve as an indicator
of potential number of wells (and reserves) affected, a more helpful
submittal would include a similar distribution of only sour wells, which
could be affected by the standard. Also, although some cost data are
provided, the process used to determine rate of return on investment and
the "acceptable" rate of return would be more useful.
As part of the standards development process, six regulatory
alternatives were identified to control S02 emissions from onshore
natural gas processing plants. Based on a review of incremental cost
effectiveness for each of these alternatives, the Administrator selected
Regulatory Alternative III as a basis for the standard. In the economic
impact analysis (Chapter 9, BID for the proposed standards), no plant
curtailments were predicted under Regulatory Alternative III and costs
were not expected to cause any increase in the number of plants unable
to cover total production costs (Table 9-27, BID for the proposed
standards). Subsequent to proposal of the standards, a revised economic
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impact analysis was conducted using a different methodology and
incorporating several updated assumptions including gas prices, equipment
life, recovered sulfur prices, and baseline sweetening costs (see
description in Appendix A). The results of the analysis were not
significantly different from the results of the preproposal analysis.
The standards are not expected to have an effect on incentives to develop
new sour gas fields. Sizes of model plants, ranging from 1.0 to
1,000 LT/D were included in the economic impact analysis. The analyses
conducted in developing the standard do not support citations from the
commenters that the standard will place an unnecessary burden on small
producers. Thus, there is no economic basis for exempting facilities
with sulfur feed rates ^1 LT/D. The 2 LT/D cutoff determination was
made on the basis of cost effectiveness.
Under all regulatory alternatives, nationwide costs of compliance
are approximately 2 percent of the total projected value of sweet gas
sales from sour natural gas processing. Thus, under Alternatives I
through VI, the impacts of S02 emission control costs on expected returns
from exploration and development are small and the effect of these
alternatives on exploration and development of new wells is likely to be
negligible.
The effects of variations in throughput are discussed later in this
section.
Comments: Four of the commenters (IV-F-1, IV-F-5, IV-D-20, and
IV-D-29) who suggested a 20 LT/D cutoff cited, as a precedent, the
20 LT/D exemption for sulfur recovery plants in the refinery NSPS.
Commenter IV-D-16 recommended a 10 LT/D cutoff and said that an
exemption for remote gas plants should be at least as large as the
exemption for urban refineries.
Response: The exemption in the refinery NSPS for sulfur plants
with less than 20 LT/D capacity is unlike the exemption in these standards
in that it represents an exemption from tail gas treatment requirements
(i.e., it is not an exemption from sulfur recovery requirements).
Furthermore, in its 4-year review of the refinery NSPS, EPA considered
lowering the 20 LT/D cutoff, based on cost-effectiveness. The reason
that the cutoff was not lowered was because refinery sulfur recovery
plants with feed rates less than 20 LT/D represent a very small fraction
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of projected growth in capacity (48 FR 57239, December 28, 1983). Cost
effectiveness was also a major consideration in determining the cutoff
for the standards for natural gas processing plants. The highest
incremental cost effectiveness (in dollars per metric ton of S02 emissions
reduced) of these standards would be about $925/Mg. This is the
incremental cost effectiveness (Alternative III vs. Alternative II) for
a plant with a sulfur feed rate of 555 LT/D. This cost effectiveness is
considered to be reasonable by the Agency; consequently, there is no
basis for exempting plants with sulfur feed rates £2 LT/D.
Comment: Commenters IV-F-5 and IV-D-13 stated that changing the
exemption to 20 LT/D would not significantly increase S02 emissions
because the recommended change would exempt less than 7 percent of total
available sulfur plant feed, or 0.25 percent of industrial S02 emissions.
Response: The fact that changing the cutoff limit to 20 LT/D would
exempt less than 7 percent of the total available sulfur plant feed and
that these small plants may contribute only 0.25 percent of total national
industrial S02 emissions, as stated by the commenter, does not alter the
Administrator's conclusions. The purpose of the cutoff is to cause the
standard to reflect BDT. The amount of emissions at issue is irrelevant
to that purpose. In any event, emissions from plants with sulfur feed
rates ^20 LT/D are considered significant by the Agency and can be
significantly reduced at reasonable costs. Emissions of S02 from plants
less than 20 LT/D, based on the information provided by the commenter,
represents over 60 percent of the emissions from the source category.
The emissions data cited by the commenters reinforce rather than obviate
the need for regulating small facilities.
Comment: Commenters IV-D-10, IV-D-18, and IV-D-20 based their
recommendations for a higher cutoff specification on the premise that
smaller plants emit substantially less S02 than larger plants, and
because controls are least cost effective at smaller plants where
compliance costs are higher. Commenter IV-D-10 suggested a cutoff of
5 LT/D; IV-D-18 suggested 20 LT/D; and IV-D-18 did not specify a cutoff
but recommended that plants less than 100 LT/D be regulated less
stringently. Commenter IV-D-22, recommending a 10 LT/D cutoff, said
that the cost of sulfur removal equipment is approximately the same
irrespective of capacity.
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Response: Small plants are regulated by the standards because they
emit S02 that can be controlled to a level reflecting BDT. A 5 LT/D
plant under typical SIP regulations can emit about 3,500 Mg (3,900 tons)
of S02 per year. As indicated in Chapter 9 of the Volume I BID
(Table 9-9), in 1979, 19 facilities with capacities less than 10 LT/D
were in operation. Over 67,500 Mg of S02 could be emitted from those
facilities, assuming each plant emits 3,500 Mg S02/year. On the other
hand, a large plant (>1,000 LT/D) may emit as much as 23,900 Mg S02
(26,400 tons S02) per year under baseline control levels. In 1979, only
one plant this size was operational. Thus, based on the distribution
in 1979, several small plants emit more S02 than one large plant. Given
the distribution of new facilities expected to be constructed in the
future, this trend will continue. The Agency considers emissions from
small plants to be significant.
The cost effectiveness for a complete range of plant sizes was
evaluated during development of the proposed standards. The maximum
cost in dollars per ton S02 removed, $1,030 [since proposal, this number
has been recalculated (see Section 2.7)], for a 1 LT/D plant under
Alternative III* was deemed by the Administrator to be reasonable. In
addition, the economic impact analysis showed no adverse effects on
small plants from Regulatory Alternative III, the alternative upon which
the standards are based. The revised analysis shows that the incremental
cost effectiveness resulting from Regulatory Alternative III is about
$l,400/Mg for a 1 LT/D plant and $840/Mg for a 2 LT/D plant (Docket
Entry IV-B-6). The cost effectiveness for 1 LT/D plants has been judged
to be unreasonable; therefore, the standards have been revised to exempt
plants <2 LT/D from the control requirements of the standards.
Comment: Three commenters (IV-D-12, IV-D-28, and IV-D-29) questioned
the availability of sulfur control technology for plants with small
(<5 LT/D and <20 LT/D) production rates. Commenter IV-D-28 added that
some information on 2-stage Recycle Selectox is claimed as proprietary
by the vendor and is, therefore, unavailable for evaluation.
Response: The Recycle Selectox technology (the technology evaluated
by the Agency for application to small plants) has been successfully
demonstrated on a commercial scale at natural gas processing facilities
in West Texas and at another facility with an acid gas stream (Claus
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process tail gas) with 2 percent H2S. Other natural gas processing
facilities employing the Recycle Selectox technology are in the planning
stages. In addition, other technologies have been advanced in recent
years (e.g., Slurrysweety., and LoCatjM, etc.) for the purpose of
recovering or removing sulfur from low flow, H2S lean acid gas streams.
On this basis, the Agency concludes that BDT exists for small affected
facilities.
With respect to any proprietary data on the Recycle Selectox process,
the Agency assumes that vendors of this process will make available all
the information necessary to satisfy a potential customer's questions.
It should be pointed out, however, that these standards do not require
the use of any particular process or technology. The Agency has the
responsibility of basing the standards on the capability of what is
determined to be the BDT. For small processing plants, that technology
is the Recycle Selectox process. Any other process capable of meeting
the required sulfur recovery efficiencies can be used.
Comment: Four commenters (IV-D-23, IV-D-27, IV-D-29, and IV-D-31)
discussed operating problems encountered by small sulfur plants. These
problems may lead to the disruption of gas plant operation. The problems
identified by the commenters included heat loss, which makes process
control difficult, and variations in sulfur concentration at the gas
plant inlet, which can sometimes make a sulfur plant inoperable. This
latter problem was said to be most significant at small plants fed by a
few wells. Commenter IV-D-27 stated that in the absence of a 10 LT/D
exemption, there should be an allowance for greater fluctuations in
sulfur recovery efficiency for plants below 10 LT/D capacity. He stated
that small plants may be connected to as few as 10 to 12 wells in contrast
to a typical plant of greater than 20 LT/D, which usually has an adequate
number of gas sources to survive the loss of one well.
Response: In response to these comments, the Agency discussed the
effect of decreased throughput on recovery efficiency with Ralph M. Parsons
Company, an engineer design firm with expertise in sulfur recovery
facilities (Docket Entry IV-E-1). Based on these discussions, the
Agency concluded that the recovery efficiencies required by the standard
are achievable and representative of BDT. Variations in throughput are
accommodated by the design of the processing equipment. The sulfur
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recovery technologies can operate over a wide capacity range. The
turndown capabilities of plants are discussed in response to comments in
Section 2.4. Process instrumentation also allows for corrections to
accommodate smaller variations occurring over shorter time intervals.
The plants evaluated by the Agency employ gas analyzers to measure the
ratio of H2S to S02 in the process tail gas as a trim control to ensure
that only the correct stoichiometric amount of process air is used to
maintain the desired 2 to 1 H2S to S02 ratio. Maintenance of the 2 to 1
H2S to S02 ratio ensures design efficiencies regardless of throughput.
Also, heat loss was not identified as an irresolvable operating difficulty.
Insulation steam tracing and other practices can be used to mitigate
potential heat balance problems. The Agency acknowledges, however, the
commenter's concern that small plants experience proportionately greater
variations in inlet conditions and corresponding operating difficulties.
It was because of this concern that plants with feed rates between 2 and
5 LT/D are required to meet a uniform 79 percent recovery efficiency
during the initial performance test and 74 percent efficiency thereafter.
These efficiencies were established below the optimal performance
capabilities to account for flow fluctuations and other uncertainties
related to day-to-day performance at facilities in this size range.
Start-of-run sulfur recovery efficiencies for the technologies considered
as BDT (i.e., Recycle Selectox, 2-stage) range from 80.6 to 92.3 percent.
Comment: Two commenters (IV-D-23 and IV-D-31) stated that small
plants are typically located in remote areas far from skilled labor
pools and are unattended 12 to 16 hours per day. The commenters propose
that these plants should be exempt from the control requirements.
Response: The Agency has evaluated the potential impacts of the
proposed standards on small plants and has revised the standards to
address the issue of small plants being unattended for 12-16 hours per
day and not having technicians sufficiently skilled to operate continuous
emission monitors.
(1) Based on the results of an incremental cost-effectiveness
analysis of the proposed monitoring requirements and an alternative
monitoring approach (see Docket Entry IV-B-31), plants with sulfur feed.
rates <150 LT/D have been exempted from continuous emission monitoring
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requirements (see Section 2.7). These plants may, instead, calculate
emission reduction efficiency daily by comparing the amount of sulfur
recovered to the amount of sulfur entering the sulfur recovery unit.
(2) The standards have also been revised to require sulfur
production and emission monitoring on a 24-hour instead of a 12-hour
basis to accommodate plants unattended for portions of the day (see
Section 2.12).
The economic impact of the standards on plants £1 LT/D has been
analyzed and determined to be reasonable. In addition, the cost
effectiveness of the standards on plants with sulfur feed rates £2 LT/D
has been judged by the Administrator to be reasonable. Thus, there is
no basis for exempting plants.
Comment: Commenter IV-D-29 stated that the proposed cutoff would
prevent process improvement in existing small gas plants. An example
was presented in which a fuel inefficient gas liquids plants would be
replaced with a new, more fuel efficient cryogenic plant. Completing
the project requires removal of acid gases from inlet sour natural gas.
If the 1 LT/D cutoff were exceeded, a sulfur plant would be required to
treat the acid gas. The commenter claimed that the cost of the sulfur
plant could make the entire project uneconomical. The commenter
recommended that the affected facility size be increased and stated that
the change would encourage small, outmoded plants to make improvements
in fuel efficiency by lessening the possibility of triggering the NSPS.
Response: The economic impact analysis (Chapter 9, Volume I BID)
and the revised economic impact analysis (see Appendix A) indicate that
under Regulatory Alternative III, upon which the standards are based, no
adverse impacts are expected for plants with sulfur feed rates greater
than or equal to 1 LT/D. The costs of sulfur removal were an integral
part of the analyses. The Agency has determined that projected new
plants with sulfur feed rates greater than or equal to 1 LT/D complying
with the proposed standards will not be unprofitable.
As discussed in the previous response, the cutoff for plant size
control requirement applicability has been changed to 2 LT/D, based on
cost-effectiveness considerations.
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2.9 CATALYST LIFE
Several commenters questioned the assumptions of catalyst life
expectancy for Glaus and Recycle Selectox processes.
Comment: Two commenters (IV-F-1 and IV-D-22) believed that catalyst
life for units at small plants may be shorter than the 4-year period
used in the basis for the proposed standards because small plants are
not staffed continuously and greater potential exists for operating
upsets resulting in catalyst degradation.
Response: Information provided by industry (Docket Entries II-B-26,
II-B-27, and IV-E-3) indicates that the useful life span of a Claus
catalyst bed ranges from approximately 1 to 7 years, with a 3-year to
5-year range occurring most frequently. The information does not show
any correlation between, catalyst life and plant size.
The Agency understands that catalyst life can be quite short, in
some cases and in other cases, much longer than average. However, based
on the information obtained during development of the standards, the
Agency continues to regard 4 years as representative of a typical useful
catalyst life.
•
Comment: The commenter (IV-F-2) stated that, based on operating
experience, the reductions in sulfur recovery efficiency listed in the
proposed standards of 1.68 percent and 1.88 percent per year for 2-stage
and 3-stage Recycle Selectox units due to catalyst degradation are much
too high. The commenter said that the Sid Richardson Recycle Selectox
unit has shown no significant decrease in sulfur recovery efficiency
because of catalyst degradation after 2 years of operation. The commenter
also stated that recovery loss (rate of reduction in sulfur recovery
efficiency) for 3-stage Claus units in the Volume I BID (Chapter 4) may
be low.
Response: The Recycle Selectox catalyst degradation rates questioned
by the commenter of 1.68 percent per year (2-stage process) and
1.88 percent per year (3-stage process) are based on process design
performance data prepared by the Ralph M. Parsons Company. The rate of
reduction in sulfur recovery efficiency for the Recycle Selectox process
was calculated from start-of-run and end-of-run efficiencies. The
4-year period is the average of the 3- to 5-year range of actual catalyst
lives experienced by sour gas processing plants surveyed during the
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development of the standards (Reference Docket Entry II-B-28). The
sulfur recovery performance data developed by Parsons assumed a 5-year
life of the Selectox catalyst and a 3-year life of the alumina Glaus
stage catalyst for the Recycle Selectox processes (^5 LT/D sulfur feed)
considered.
With specific regard to the Recycle Selectox process, the Agency
realizes that the limiting factor on catalyst life is the alumina Claus
catalyst and not the Selectox catalyst. The EPA also realizes that
Claus catalyst life is influenced by the operation of the particular
process. The survey mentioned above indicated Claus catalyst lives as
short as 1 year (due to process malfunctions) and as long as 6 years or
more with steady process operation. The limited data available on
Selectox catalyst degradation (Reference Docket Entry II-D-57) indicate
little loss of performance with time reportedly due to its insensitivity
to fouling from carryover of organic compunds in the acid gas. The
Claus catalyst, however, is believed to degrade at about the same rate
in the Recycle Selectox process as it does in other Claus-based sulfur
recovery plants. The 1.68 and 1.88 percent per year degradation rates
are acknowledged as being the "high end" of what would be expected under
normal operation conditions and are attributed to degradation of the
Claus catalyst and not the Selectox catalyst.
The Selectox process referred to by the commenter is installed to
treat the tail gas from a sulfur recovery unit. As such, it would not
experience the hydrocarbon fouling and resulting catalyst degradation of
a Recycle Selectox plant installed on an acid gas stream from a sweetening
unit. Consequently, his conclusion about no decrease in sulfur recovery
efficiency may be correct only for tail gas units.
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2.10 1000°F TEMPERATURE REQUIREMENT
The Agency received fifteen comments (IV-F-1, IV-F-2, IV-F-3,
IV-F-5, IV-D-2, IV-D-8, IV-D-16,. IV-D-18, IV-D-22, IV-D-23, IV-D-24,
IV-D-27, IV-D-29, IV-D-30, and IV-D-31) regarding the requirement (in
the proposed standards) that incinerators be operated at 1000°F. All
were in opposition to the specification of a certain temperature. The
bases of this opposition and alternatives offered by the commenters are
presented below.
Comment: Eight commenters (IV-F-1, IV-F-2, IV-F-5, IV-D-8, IV-D-23,
IV-D-24, IV-D-29, and IV-D-30) pointed out that the requirement precludes
the use of catalytic incinerators which are capable of effectively
converting H2S to S02 at temperatures below 1000°F.
Comment: Two commenters (IV-D-2 and IV-D-16) suggested that
temperature alone does not ensure the oxidation of residual sulfur-
containing compounds. Incinerator temperature in incinerators is only
one of several factors which affects complete combustion. These factors
include residence time of gas in the combustion zone of the incinerator
and the mixing of sulfides with make-up air.
Comment: Eight commenters (IV-F-3, IV-F-5, IV-D-16, IV-D-22,
IV-D-23, IV-D-24, IV-D-27, and IV-D-29) stated that the 1000°F requirement
is wasteful in that it results in unnecessary increased fuel consumption.
Comment: Six commenters (IV-F-3, IV-D-8, IV-D-18, IV-D-27, IV-D-29,
and IV-D-31) recommended that temperature requirements for incinerators
be the minimum temperature necessary to oxidize all sulfur compounds
to S02. It was suggested that this temperature be determined during the
performance test and that a 95 to 99 percent conversion efficiency would
establish a site-specific temperature requirement.
Comment: One commenter (IV-D-24) suggested the requirement of an
850°F minimum thermal oxidation temperature and a 650°F minimum catalytic
oxidation temperature for sulfur recovery incinerators.
Comment: One commenter (IV-D-16) stated that if the only purpose
of the temperature requirement is to ensure conversion of H2S to S02 so
that the continuous S02 monitor can detect sulfur leaving the stack,
then a provision should be added to remove the 1000°F temperature
requirement if a total sulfur monitor is installed that can accurately
measure total sulfur emissions (COS, CS2, H2S, and S02).
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Alternatively, the commenter stated that if the purpose of the
temperature requirements is related to concern of health effects of
unburned H2S, the Agency should state that fact and set a maximum
allowable H2S stack concentration, based on the Agency's risk assessment
of the impacts of H2S on public health. In such a situation, the plant
owner could decide how to best meet the health standard based on
conditions at his facility. At some plants, the commenter claimed that
"less than complete" combustion may be acceptable if the H2S concentration
is within the health standard limit.
Comment: One commenter (IV-D-30) recommended deletion of the
1000°F temperature requirement because the requirement was a design
limit and conflicted with the provisions of Section lll(b)(5) of the
Act, which prevents the Administrator from adopting a particular emission
control technology. The commenter stated that the Agency may impose a
design or work practice standard only if it is not feasible to prescribe
or enforce a standard of performance. Because, in the commenter's
opinion, the proposed standard contains a standard of performance in the
form of a minimum sulfur recovery efficiency, Section lll(b)(5) of the
Act appears to preclude the adoption of design criteria.
Response: The purpose of the temperature requirement was to ensure
complete oxidation of total reduced sulfur (TRS) in the tail gas to S02.
Since the required monitoring devices measure only S02, total conversion
to detectable species is necessary for accurate emission and sulfur
recovery efficiency determinations. In the absence of total conversion,
monitors for H2S, TRS, and S02 would be necessary.
The Agency understands that incinerator efficiency is a function of
design (residence time, flow patterns, etc.) and operation (temperature).
While the design parameters are specific and predetermined for each
incinerator, the operatonal parameters can be more easily adjusted.
The Agency has reviewed the requirement that incinerators be operated
at 1000°F. Based on comments from both industry representatives and
State regulatory agencies, the Agency is deleting the 1000°F temperature
requirement for incinerators. Instead, a site-specific temperature, to
be determined during the performance test, will be required for those
facilities required to have stack monitors and electing to monitor only
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S02 in the stack gas. This temperature must ensure conversion of
£98 percent of the sulfur compounds to S02, in order to ensure an accurate
sulfur recovery efficiency calculation. The use of site-specific minimum
temperature determinations will allow plant operators to provide for
oxidation of residual sulfur compounds to S02 in a manner best suited to
that particular operation. Thus, catalytic incinerators will not be
precluded from use in complying with the proposed standard. Also, if a
given plant demonstrates that operating at a temperature less than the
previously required temperature of 1000°F, will yield £98 percent
conversion of sulfur compounds to S02, then that lower temperature will
be the minimum required for that plant. If, on the other hand, a given
plant cannot attain £98 percent S02 conversion ratio at 1000°F, then
that plant will be required to operate at a higher temperature or to
monitor both S02 and other unoxidized sulfur compounds (TRS monitoring).
Deleting the 1000°F temperature requirement and replacing it with a
minimum temperature to ensure £98 percent S02 conversion does not indicate
a more lenient approach. Instead, plant operators can more economically
comply with the proposed standard, and operate incinerators at lower
temperatures, as long as the oxidation process ensures £98 percent of
the total sulfur content of the stack gases (expressed as S02) in the
form of S02.
Response to the commenter (IV-D-30) who stated that the temperature
requirement conflicted with Section 111 of the Act is as follows:
The proposed standards in question are performance standards in
which the equations for determination of emission limits are consistent
with the intent of the Act for performance standard requirements. The
1000°F temperature requirement for incinerators was a requirement relating
to the operation or maintenance of a source to assure continuous emission
reduction. The Agency is authorized by Section 302(1) of the Act to
impose such requirements as part of the performance standard.
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2.11 FORMAT OF THE STANDARD
Comment: Two commenters (IV-F-1 and IV-D-8) requested that the
initial compliance sulfur recovery efficiency requirements be used as a
guideline, not a standard. In their opinion, the initial efficiency
requirements may necessitate installation of an expensive unit to attain
initial compliance and the unit would not be needed thereafter to meet
the efficiencies required by the second equation. The example was
offered of a Sulfreen or CBA process that may be needed to meet the
initial compliance requirements for a 100 LT/D facility with 80 percent
H2S in the acid gas plant. A 3-stage Glaus process plant likely could
meet the long-term requirements.
Another commenter (IV-D-16) stated that the proposed standard
consisted of two standards, a "start-up standard" and a "less restrictive
operational standard." The commenter claimed that the first standard is
excessive and unwarranted and that plants may have to install additional
control equipment to meet the "first standard," while less costly
equipment could meet the "second standard" requirements. The commenter
recommended that the NSPS should be modified to use the "first standard"
as a guideline and not a requirement.
Response: In referring to the "two compliance tests" and
"two standards" the commenters are referring to the first equation which
determines the minimum emission reduction that must be achieved during
the initial performance test and the second equation which determines
the minimum efficiency that must be achieved on a continuous basis.
Only one "compliance test" is required, providing the facility adequately
demonstrates compliance with the initial sulfur recovery efficiency
requirement during the performance test and demonstrates through the
monitoring requirements that the continuous sulfur recovery efficiency
requirement also is being achieved. A second, or multiple compliance
test(s) may be required by the permitting authority to prove compliance
with the continuous sulfur efficiency requirement. This normally would
occur only if the continuous monitoring measurements indicated excess
emissions at the facility.
The first equation is based on the recovery efficiencies achievable
using BDT with a 1-year old catalyst. The first equation reflects the
initial performance of the BDT upon which the standard is based and is
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designed to cause installation of technology which will initially achieve
this level of performance. The performance established by this equation
is expected to influence the sulfur recovery process which an owner or
operator selects to comply with the standards. It is the equation that
is used by enforcement personnel to determine initial compliance.
The second equation ensures proper operation and maintenance of the
sulfur recovery unit on a continuous basis. The second equation by
necessity requires a lower efficiency than the first since it is based
on catalyst degradation rates over a 4-year period. The purpose of the
second equation is to provide an indication to enforcement officials of
daily operation and maintenance. Based on daily calculations of the
actual recovery efficiency of a plant in relation to its required
efficiency, enforcement officials will determine whether a compliance
problem exists that warrants a compliance test. The results of a
compliance test, conducted after an initial demonstration of compliance,
would be compared to the second equation to determine compliance.
The cost analyses prepared in support of the standards are the
costs of the technologies representative of BDT that will be used to
achieve the higher initial sulfur recovery efficiency requirement.
Consequently, the cost of the technologies that will be used to meet the
first equation have been evaluated and determined to be reasonable. For
these reasons, the initial sulfur recovery efficiency is necessary as a
requirement and is not merely a guide.
Comment: Another commenter (IV-F-4) stated that the "sliding
standard" would be difficult to enforce and unfair to certain plants.
He claimed that the requirements of an affected facility would change
from day to day and reviewing plant records would require significant
portions of enforcement agency personnel time.
Comment: Commenter (IV-D-22) recommended a single S02 emissions
rate format for the standard instead of the proposed emission reduction
efficiency format. The commenter stated his concern is that the proposed
efficiency format presents a "moving target" because the HaS/CC^ ratio
does not remain constant for the life of the plant and could place
owners/operators in violation of the standard before the requirements of
the standard could be determined.
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Response: The Agency assumes that by "sliding standard," the
commenter is referring to the fact that the required sulfur reduction
efficiency for plants over 5 LT/D varies with the sulfur feed rate and
the acid gas ratio (i.e., as the ratio of volume percent H2S to C02
increases, the sulfur recovery efficiency increases). Thus, the required
recovery efficiency for a given plant may vary according to changes in
the sulfur feed rate and acid gas ratio. However, the degree of
variability will depend on the individual plant. In many instances, the
sulfur feed rate and H2S concentration are expected to be essentially
constant for long periods.
Representatives of the natural gas processing industry have stressed
that sulfur feed rate and acid gas ratios are directly related to
efficiencies. The sliding standard accommodates this relationship in
that it considers the dependency of emission reduction efficiency on the
mass flow rate and concentration of H2S in the acid gas stream at a
given plant. A uniform mass or concentration limit format (specifying a
single mass value per day or a single value for required efficiency)
would not reflect the fact that achievable reduction efficiencies are a
function of the factors cited above. The ability of an owner or operator
to comply with a single value standard on a continuous basis could not
be assured.
The Agency believes that the emission reduction efficiency format
for determining compliance with the standards is reasonable. The daily
sulfur recovery determinations can be easily plotted on a graph either
manually or with automated data reduction equipment. Such graphs would
provide the basis for excess emission reports sent to the enforcement
agency. State enforcement personnel would not need to make plant visits
to inspect plant records under normal circumstances.
The equations used to determine efficiency levels represent
continuous functional relationships between efficiency levels required
and the operational conditions which vary from plant to plant (i.e.,
sulfur feed rate and mole percent H2S). Variations in acid gas ratios
do not significantly affect the calculation of reduction efficiency.
The calculation of the required efficiency is based on actual operating
conditions each day. The required efficiency is then compared to the
actual efficiency enabling timely adjustments.
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2.12 MONITORING AND PERFORMANCE TEST REQUIREMENTS
Comment: Nine commenters (IV-F-1, IV-D-16, IV-D-18, IV-D-19,
IV-D-22, IV-D-23, IV-D-28, IV-D-29, and IV-D-31) stated that small
plants, especially those in remote areas, do not have staff on site
24 hours per day and therefore it would be difficult to obtain twice
daily measurements for calculating sulfur removal efficiency.
One commenter (IV-D-19) suggested that when "R" (achieved sulfur
emissions reduction efficiency) is greater than a midpoint, "M," between
"Z" (required sulfur emission reduction efficiency) from equation 1
and "Z" from equation 2 in the standard, "R" should be calculated once a
month. When "R" is less than or equal to "M," "R" should be calculated
once a week.
Another commenter (IV-D-27) recommended that "R" be calculated on a
weekly basis because the 12-hour interval requirement creates additional
gauging, reading, and calculations at considerable expense and that
measurements, other than those necessary for operational control, are
frequently taken no more often than every 24 hours and perhaps not at
all on holidays and weekends.
The commenter also stated that emission reduction efficiency is
maintained by control of the H2S/S02 ratio. Many plants take spot
readings of total emissions to confirm recoveries.
In the opinion of the commenter, the imposition of a specific time
interval for calculation is unwarranted and unnecessary and each plant
may have valid reasons to use other schedules. He claimed that selection
of a specific calculation time interval will have no effect on emission
reduction efficiency. He stated further that the recovery determined in
such intervals will be very misleading for all the sub-dewpoint adsorption
processes, CBA, Sulfreen, MCRC, etc. Most often, the units will not
complete a full cycle within 12 hours. Sulfur production during
one 12-hour period may be substantially lower than that shown for the
next 12-hour period. The reporting system could thus erroneously label
alternate periods as periods of excess emissions.
Response: The Agency has reviewed the requirements for performing
readings every 12 hours. The 12-hour interval was selected to give
results comparable to those measured during the 12-hour initial
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performance test. The Agency performed tests which show that the
variation of 12-hour average results, as compared to 24-hour average
results, is not large. Since the results of 24-hour measurements are
expected to be essentially the same as 12-hour measurements and since
normal practice of sulfur recovery plant operators is to determine the
production rate on a daily basis, the requirement has been changed to
allow calculation of recovery efficiency on a 24-hour basis.
The purpose of determining achieved sulfur emissions reduction
efficiency "R" on a regular basis is to ensure proper operation and
maintenance. Monthly determinations of "R" would not provide performance
trend data required to ensure proper operation and maintenance of the
sulfur recovery equipment.
The selection of which 24-hour interval to use is left to the
discretion of the plant owner or operator. However, the interval must
be consistent (i.e., the same time each day). (Note: The regulation,
§§60.646(b)(5) and 60.647(b)(l), has been changed to eliminate the
specific "midnight" and "noon" clock intervals for the determination
of "R.") The adsorption processes will not affect the calculation of
efficiencies on a 24-hour basis. The Agency regards this 24-hour interval
as a reasonable interval to ensure proper operation and maintenance.
Comment: Three commenters (IV-D-13, IV-D-27, and IV-D-29) stated
that gauging the sulfur pit or measuring sulfur production by any method
over a short-term (less than 24 hours) period is inaccurate. According
to commenter IV-D-13, this is due to liquid sulfur entrainment in the
catalyst beds, a normal operating phenomenon, which results in wide
fluctuations in short-term production rates because of loading and
unloading of liquid sulfur in catalyst beds. The commenters also stated
that accurate sulfur tank volume measurements are not always attainable
because of variations in the thickness of sulfur cakes on the wall
caused by temperature changes. Because of such characteristics inherent
in the sulfur recovery process, the commenters claimed that short-term
production test requirements are not appropriate.
One commenter (IV-D-29) added that production rate data are not
collected during weekends because of the inaccuracy of pit gauging. He
stated that the operator relied on monitoring the H2S/S02 ratio with a
ratio controller to maintain plant efficiency.
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Three commenters (IV-F-3, IV-D-27, and IV-D-29) questioned the
2 percent accuracy of sulfur production measurements, as stated
in §60.646(b)(2).
Response: As discussed in the previous response, the Agency has
changed the sulfur recovery measurement interval from 12 hours to
24 hours. The 24-hour interval should alleviate the problems associated
with the fluctuations in production rates resulting from liquid sulfur
entrainment in the catalyst beds.
Sulfur cake buildup is not expected to pose a significant problem.
The Agency made several contacts which indicated that sulfur tanks are
either located below ground or are insulated. In both instances, the
buildup of sulfur cake is minimized. In these contacts, cake buildup
was not identified as a significant concern.
The source of the questioned ±2 percent accuracy estimate for
sulfur production measurement methods is a technical report, "Capability
of the Modified Glaus Process," developed by Western Research and
Development Corporation (Docket Entry II-I-41). Based on the nature of
the measurement method, EPA believes that the ±2 percent uncertainty
estimate is reasonable. The expected method of measurement is to measure
the depth of liquid sulfur in the storage tank at the beginning and end
of the measurement period. (Note the proposed 12-hour period is being
changed to a 24-hour measurement period.) The depth measurement should
be accurate to within at least plus or minus 0.5 centimeters. On a
typical sulfur pit (3x6x5 meters) for a sulfur recovery plant
producing 30 Mg/D of sulfur, this would amount to a sulfur mass
measurement error of about plus or minus 0.6 percent over a 24-hour
compliance period (Docket Entry IV-B-2). This measurement, with
subsequent calculations based on tank geometry and sulfur density,
should yield a total error of no more than ±2 percent.
Monitoring requirements are designed to ensure proper operation and
maintenance at all times. Deviations from the required monitoring
schedule on weekends would be contrary to the intent of the standards.
Comment: Twelve commenters requested that smaller plants, unattended
for more than 12 hours per day, be exempt from the requirements for
continuous S02 monitoring. One commenter (IV-D-19) suggested a 10 LT/D
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cutoff. Commenter IV-D-23 suggested 20 LT/D. Two commenters (IV-D-22
and IV-D-25) suggested 50 LT/D. Commenter IV-D-18 suggested 100 LT/D.
Commenters IV-F-5, IV-D-11, IV-D-13, and IV-D-29 recommended that the
cutoff be 800 LT/D. Commenter IV-D-27 suggested 1,000 LT/D.
Commenter IV-D-20 recommended that plants less than several hundred LT/D
be exempted from continuous S02 monitoring and commenter IV-D-30 suggested
that only relatively large plants be subject to continuous monitoring
requirements. These commenters stated that only the larger plants were
staffed with technical operating and maintenance personnel.
Response: Two methods of calculating emission reduction efficiency
are considered appropriate for these standards. One method involves
continuously measuring S02 emissions and calculates efficiency by
comparing the amount of sulfur recovered to the sum of the sulfur emitted
and the liquid sulfur recovered [sulfur recovered -f (sulfur emitted +
sulfur recovered)]. The second method does not involve measuring
emissions; instead efficiency is calculated by comparing the amount of
sulfur recovered to the amount of sulfur entering the sulfur recovery
unit (sulfur recovered T inlet sulfur). The first of these methods
provides the md"st accurate determination of efficiency and, since
emissions would be monitored on a continuous basis, provides the
owner/operator and enforcement personnel with an ongoing indication of
performance of the sulfur recovery unit. For a plant achieving 94 percent
sulfur removal efficiency, the efficiency calculations using the emission
measurement approach are estimated to have about a ±0.6 percent error.
Calculations using the second method are estimated to have an error of
about ±5 percent.
The accuracy of the emission monitoring method makes it the
preferrable method in most cases. However, the Agency recognizes that
operating these continuous emisson monitors may necessitate the presence
of a trained instrument technician on a part-time, or, in some cases, a
full-time basis. The Agency has considered the costs of these technicians
in estimating costs and evaluating the incremental cost analysis for the
sulfur recovery technologies and regards these costs to be reasonable.
However, the Agency recognizes that smaller plants pay a proportionately
higher cost for monitoring equipment (relative to total plant costs)
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than larger plants and gain a proportionately small benefit in emission
reduction from the more accurate monitoring method.
The Agency performed an analysis, which simulated the additional
emission reduction resulting from the more accurate emission/production
method compared to the inlet/production method. The potential additional
emission reduction was evaluated along with the additional costs of the
stack monitoring equipment (including a full-time trained technician and
maintenance costs). Based on this analysis, the Agency has exempted
plants with sulfur feed rates less than 150 LT/D from the requirements
for continuously monitoring S02 emissions. These plants are required to
calculate emission reduction efficiency on a daily basis, but they are
required to measure inlet sulfur once every 24 hours instead of
continuously monitoring stack gas S02 concentrations.
For plants ^150 LT/D, the Agency will continue to require continuous
emission monitoring to maintain the accuracy afforded by that method.
Comment: Eleven commenters (IV-F-2, IV-F-3, IV-F-5, IV-D-8, IV-D-19,
IV-D-20, IV-D-25, IV-D-27, IV-D-28, IV-D-29, and IV-D-31) questioned the
economical justification of continuous S02 monitors. Specifically
mentioned were installation and maintenance costs for the monitoring
system and labor costs. Costs presented by commenters included:
• (IV-D-25): Purchase and installation of a S02 continuous
emission monitor on a 160 LT/D SRU incinerator costs were
over $140,000.
• (IV-D-29): Commenter cited a report stating $100,000 to
$150,000 actual cost estimate for a continuous S02 monitor
installed at a Chevron refinery.
• (IV-D-19): Commenter reported that three companies had total
installed costs of $46,000 (1979 dollars), $85,000 (1983
dollars), and $144,000 (1983 dollars) for continuous S02
monitors.
• (IV-D-8): Commenter reported that in the first 2 months
of 1984, 90 man-hours ($2,130) were spent on scheduled
maintenance and 165 man-hours ($4,236) were spent on trouble
calls for S02 monitors.
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• (IV-D-31): Commenter said that in 1983 his company spent
$30,000 for parts and outside technicians to repair one monitor
and that company labor dedicated to that monitor exceeded
$13,000.
Response: The Agency has taken into consideration the cost of S02
emission monitoring systems found in the literature, from vendors, and
through field experience with similar monitoring systems. A system to
meet proposed monitoring requirements would include a device to measure
sulfur, a stack gas velocity flow meter, and a data integration instrument.
If a flue gas oxidation unit is used, an S02 analyzer would also be
included. In the Volume I BID, an investment cost of $45,000 was
estimated based on data provided by Western Research and Development
Corporation (Docket Entries II-E-28, II-E-29, and II-E-30). The
annualized operating cost, $40,000 per year, was also derived from these
data.
The Agency has reevaluated these costs and concluded that they
continue to be reasonable estimates of the cost of installing and operating
an in-stack continuous S02 monitor. The $40,000 per year estimate
includes $17,000 per year for operating technician labor, $5,000 per
year for maintenance, and $18,000 per year capital charge (based on a
3-year monitor life assumption). The EPA also developed high and low
estimates to reflect the range of costs that could be expected. The
high estimate is $65,000 per year and the low estimate is $33,000 per
year (see Docket Entry IV-B-4). For plants with feed rates £150 LT/D,
these costs are considered reasonable in view of the additional emission
reduction that would be achieved with continuous monitors.
One report, prepared by Radian (Docket Entry IV-A-2) and referenced
by commenter IV-D-29, does cite a cost of $100,000 to $150,000 as an
estimated cost of a fully installed unspecified operational S02 continuous
emission monitoring system. One of the authors in this report was
contacted for a breakdown of these costs. He stated that these figures
included hardware, installation, training, start-up costs, and other
in-house expenses, and that the estimate represented that company's
estimate of what it would cost to get the system working well. Several
of these total cost components would be considered "overhead" by most
plants and, thus, would not be included in most estimates of continuous
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monitoring systems. It should be noted that other continuous emission
monitoring costs cited by other companies surveyed in the same report
closely match those estimated by the Agency.
To better understand the significance of the reported operating
costs for monitors, commenter IV-D-8 was contacted to determine the
number of monitors included in the aggregate cost data provided (Reference
Docket Entry IV-D-14). The cost data were found to include costs for
tail gas monitors for four sulfur recovery units in separate facilities.
Therefore, assuming the costs for maintenance and trouble calls presented
by the commenter of $2,310 and $4,236, respectively, are representative
of a 2-month period for four monitors, the yearly cost for a single
monitor would be approximately $9,800. The $40,000/year estimate in the
BID for the proposed standards included $5,000/year for maintenance and
$17,000/year for labor for routine and nonroutine service. The
commenter's $9,800/year estimate is in line with these estimates.
Commenter IV-D-31 was contacted for clarification of expenditures
for parts and outside labor for monitor repair (see Docket Entry IV-E-2).
It was determined that the monitor was installed in 1978 and the system
overhauled in January of 1980. The $30,000 expenditure in 1983 apparently
represents maintenance and/or replacement costs for a 5-year-old system.
Given the overhaul in early 1980, it would be reasonable to prorate the
$30,000 over a period of 4 years, or $7,500 per year. Commenter1s
$13,000 in 1983 for company labor is in line with the Agency's $17,000 per
year estimate. Commenter apparently elected to repair, rather than
replace, the monitoring system. Given the age of the monitoring system
and the distribution of expenses over the corresponding time frame,
these expenditures are consistent with the Agency's estimates.
The Agency recognizes that exceptions to the estimated costs will
occur. However, the preponderance of data supports the estimates and
the Agency regards the basis for these estimates as reasonable.
Comment: Eight commenters (IV-F-2, IV-F-5, IV-D-10, IV-D-13,
IV-D-24, IV-D-27, IV-D-28, and IV-D-29) questioned the accuracy,
reliability, and availability of S02 continuous monitors. One commenter
(IV-D-13) stated that the uncertainties (volumetric flow rate, molecular
weight, and water content of the stack gas) associated with continuous
monitoring are substantially greater than the ±0.6 percent value reported
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in the proposed standards. He recommended that the sulfur recovery
equation in 40 CFR 60.642(a) be reevaluated to address this relative
inaccuracy.
Two of the commenters (IV-F-5 and IV-D-13) stated that continuous
S02 monitors are unproven technologically, that they require excessive
amounts of maintenance and specially trained employees, and that these
employees are not available at remote locations. Commenter IV-D-24
quoted a Radian study which reported only two continuous S02 monitors in
petroleum extraction industry sulfur recovery plants, both of which were
located in large plants. The commenter reported that the study indicated
"about 75 percent of an instrument technician's time is used for the
operation and maintenance of ... one analyzer." The commenter also
quoted the Volume I BID (pg. D-7) which indicated that no Agency field
evaluations were conducted and that only vendor information was available
from which to judge the monitor's accuracy, reliability, and operability.
The commenter concluded that there are not sufficient data available at
the present time to warrant the use of continuous S02 monitors.
Commenter IV-D-29 stated that the Agency relied on vendor information
and literature sources (Volume I BID, pg. D-7) for data concerning
availability, operation, and maintenance for continuous S02 analyzers
without providing citations to the information. He also referenced the
fact that the Agency had "not conducted field evaluations of these
systems" and also did not provide laboratory testing data of continuous
analyzers.
One commenter (IV-F-2) stated that only one supplier of S02
continuous monitors is known to him.
Response: Continuous S02 monitoring is required to ensure that
sulfur recovery operations are properly operated and maintained on a
continuous basis. At the time of development of the Volume I BID, the
Agency did rely on vendor information and literature sources for data
concerning S02 analyzers because that was all that was available. Since
that time there have been further studies conducted for the Agency
(Docket Entries IV-A-1 and IV-A-3). These studies verify that S02
continuous emission monitors (CEM's) are in use at many refineries and
natural gas processing plants. The number of CEM's identified is
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sufficient to establish the commercial availability and applicability of
CEM's. Commercially available monitors show good (e.g., generally
greater than 95 percent up-time) performance.
In response to the commenter's (IV-F-2) statement that there was
only one supplier, at least four vendors of continuous S02 monitors are
known to EPA. These include Western Research and Development, duPont,
Lear-Siegler, and Dynatron.
The ±0.6 percent uncertainty estimate was based on a conservative
estimate of uncertainty in the emission monitoring method (Docket
Entry II-I-41). The ±0.6 percent uncertainty value represents a
combination of uncertainty values associated with the measurements
involved in the calculation of sulfur recovery efficiency and not the
uncertainty associated with the S02 emissions measurement alone.
Literature from S02 mass monitoring equipment vendors (Docket
Entry II-D-34) indicates that such systems exhibit accuracy of ±5 percent.
The Agency assumed an accuracy of ±10 percent in this measurement system.
Thus, the ±0.6 percent uncertainty in the calculated sulfur recovery
efficiency should be conservative.*
The Agency recognizes that operation and maintenance of continuous
emission monitors may require trained instrument technicians. The costs
for trained technicians were included in the Agency's estimates of
monitoring costs. For a discussion of the revision of the standards to
exempt plants <150 LT/D from continuous monitoring requirements, refer
to the responses earlier in this section.
*The 0.6 percent uncertainty estimate is derived from the measurement.
uncertainties of the sulfur production rate (±2%) and the emission
rate (±10%) used in calculating the sulfur recovery efficiency. The
derivation is made consistent with a standard propagation of error
formula for equations of the form S/(S+E), which is the formula used to
calculate the sulfur recovery efficiency. (See Docket Entry IV-B-7 for
specific information about the propagation of error formula and the
relationship between the uncertainties of the measured sulfur production
rate, the measured emission rate, and the calculated sulfur recovery
efficiency.) Intuitively, one might not expect the 0.6 uncertainty to
result from the higher 2 and 10 percent uncertainties of the measured
values. However, this results from the form of the propagation of error
formula and the relative magnitudes of the sulfur production rate (S)
and the emission rate (E) for plants with sulfur recovery efficiencies
in the 90 to 99 percent range.
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Comment: One commenter (IV-F-3) stated that industry should not be
required to achieve the high level of accuracy and reliability of S02
monitoring in the proposed standards until monitoring equipment is
available which can adequately respond to the wide day-to-day variations
in plant operating conditions. The commenter claimed that the velocity
of the incinerator stack gases can vary up to 400 percent with concomitant
static pressure changes of up to 200 percent. For these reasons, the
commenter stated that measured emission results would be inaccurate.
Response: Information gathered by EPA does not show the wide
variation in incinerator stack gas flows and static pressure changes
reported by the commenter. Research performed by the Western Research
and Development Corporation shows that incinerator stack gases vary
between about 75 and 110 percent (see Docket Entry II-I-68). The stack
gas velocity does not vary in proportion to the sulfur production capacity
because at lower production rates the feed and combustion in feed rates
to the incinerator are increased to maintain the temperature at a high
enough level to oxidize the residual TRS to S02. Combustion gases from
the additional feed partially affect the decreased stack gas volume from
decreased sulfur production volume. When the system stack is designed
to accommodate typical flow velocities, commercially available S-type
pi tot tubes are capable of accurately measuring up to 400 percent
variation in stack gas velocity. Therefore, accurate emission measurement
results are possible with the velocity variations cited by the commenter.
Comment: The commenter (IV-F-2) stated that the continuous
monitoring requirements of paragraph 60.646 are difficult to attain
because of the corrosive nature of hot stack gas and the lack of choices
in suitable continuous monitors for flow rate. The commenter recommended
the following alternate monitoring requirements for stack gas flow rate
and stack gas S02 content to determine S02 emissions.
1. Continuous monitoring of S02 and 02 in stack gas emitted to
the atmosphere during initial performance test.
2. Annual performance tests of sulfur recovery units analyzing
all inlet and outlet streams, measured over a 24-hour period
and submittal to EPA of sulfur recovery measured.
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3. Correlate S02/02 from test data and/or calculations to measure
sulfur recovery to allow estimation of sulfur recovery in
interim periods between tests.
The commenter also provided alternative procedures for quarterly or
semiannual sulfur recovery determinations, which could be performed with
usual plant laboratory equipment and could be conducted by in-plant
personnel. The method was quoted as being accurate to within plus or
minus 0.5 to 1.0 percent of the sulfur recovery efficiency.
Response: The incinerator stack gas is not expected to be as
corrosive as indicated by the commenter because the temperature of the
incinerator stack gases is maintained in most instances well above the
dew point. Incinerator stack gas temperatures of the units tested by
the Agency ranged between about 900 and 1150°F. Assuming typical moisture
concentration in the stack gas of 25 percent and an upper boundary S02
concentration of 40 ppmv, the dew point can be calculated to be about 315°F
(see Docket Entry IV-B-5). The calculation supports the position that
the dew point likely will not be reached and the environment in the
incinerator stack, therefore, should not be corrosive. With the use of
heated, corrosion resistant sample lines and heated monitoring equipment,
temperatures in the monitoring system can be maintained above the dew
point and corrosion problems in this equipment similarly can be avoided.
During development of the proposed standards, the Agency considered
the alternative method for continuous monitoring proposed by the commenter,
which correlates S02 and 02 levels to efficiency. The Agency rejected
this approach because the S02/02 correlation must be made for each
individual sulfur recovery unit inlet stream condition. Because of the
fluctuations in stream conditions, extensive testing would be necessary
to establish a valid S02/02 correlation. Therefore, the Agency decided
against this alternative method.
The commenter's suggestions for alternative monitoring methods were
reviewed by the Agency. The Agency believes that the continuous
monitoring strategies outlined in the proposed preamble, coupled with
daily emission reduction efficiency verifications, provide a more
realistic and more accurate account of the operating status of the
plant. Checking sulfur recovery efficiency with performance tests once
a year as suggested by the commenter would not provide any indication of
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how the plant is functioning in-between tests. It also would fail to
provide the plant operator with data indicating possible process changes
needed to respond to day-to-day and month-to-month changes in acid gas
characteristics to maximize plant efficiency. Therefore, an annual
check would not assure proper operation and maintenance of the plant.
The continuous monitoring and the daily check on emission reduction
efficiency do provide these data.
Comment: The commenter (IV-D-10) recommended that the continuous
emission monitoring requirement be deleted because periodic performance
tests would be adequate to determine compliance.
Response: The continuous emission monitoring requirements are
intended to assure proper operation and maintenance of the sulfur recovery
equipment on a continuous basis and are not a measure of compliance.
The monitoring requirements are intended to provide both owners/operators
and enforcement personnel an accurate indication of daily performance of
the recovery system. Based on these daily data, plant personnel can
make adjustments in operation to ensure that required recovery
efficiencies are maintained. Enforcement personnel will use these data
to decide whether problems exist which may warrant a compliance test. A
requirement for a periodic compliance test alone would not provide
sufficient information to determine whether the systems are being properly
operated and maintained on a continuous basis.
Comment: Nine commenters (IV-F-1, IV-0-13, IV-D-18, IV-D-19,
IV-D-23, IV-D-27, IV-D-29, IV-D-30, and IV-D-31) regarded the quarterly
verification requirements as excessive. The commenters mentioned that
outside contractors would be required to perform the monitoring, and
that quarterly testing using Method 6 would be expensive.
Commenter IV-D-27 suggested alternate methods, such as ultra-violet
light, length-of-stain tubes, and gas chromatography, for obtaining
intermediate data. Commenter IV-D-29 stated that ratio controllers are
used to monitor the Claus process and implied that these ratio controllers
could be used as an alternative. He said that the ratio controller is
periodically reset using the Tutwiler or similar procedure. This
commenter also claimed that each quarterly test, as required by the
standard, would cost $25,000.
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Response: The initial performance tests require specialized
equipment and personnel experienced in stack sampling and, therefore,
may warrant the use of contract firms. This initial test is required
only once. Method 6 performance tests are required for S02 emissions
measurements during the initial performance test. Other than this
start-up requirement, Method 6 tests are not required by the standards.
Quarterly measurements (now, daily) are limited to measurements of H2S
concentration and volumetric flow rate of the acid gas feed to the
sulfur recovery plant. Plant personnel are capable of performing these
measurements. The expense involved in the quarterly procedures has been
considered in the cost analysis and is considered by the Agency to be
reasonable.
In accordance with the General Provisions (40 CFR 60.8), alternative
methods may be approved providing they are equivalent to the methods
listed in the standard.
Comment: Two commenters (IV-D-18 and IV-D-29) recommended that
continuous TRS monitoring requirements [60.646(b)(4)] be deleted from
the standard because TRS monitoring instruments are not commercially
available and are not necessary for accuracy. Commenter IV-D-29
questioned the statement made by the Agency in the Volume I BID (pg. D-7)
that a total reduced sulfur analyzer would be used to evaluate total
sulfur emissions. He stated that omission of TRS monitoring would
result in a 0.02 percent difference in plant efficiency (no specific
data were given) and claimed that the Agency agreed that this difference
was acceptable because measurement of sulfur production rate is accurate
only within 5 percent (49 FR 2665).
Response: Use of TRS monitors is required by the standards only if
compliance with §60.642(a) or (b) is accomplished by use of a reduction
control system not followed by a continually operated incineration
device. It should be noted that use of these monitors will not be
required until either the Agency determines the applicability- of the
existing Performance Specification #5 to natural gas processing plants
or promulgates a new performance specification for TRS monitors in
natural gas processing plants.
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These monitors are available from a number of manufacturers (e.g.,
Applied Automation, duPont, Bendix). Users of these continuous emission
monitors at sulfur recovery units in refineries and natural gas plants
have been identified in an EPA study (Docket Entries IV-A-1 and IV-A-3).
In the absence of an operating incinerator, TRS monitoring data are
required to determine sulfur emission rates. For recovery units with an
operating incinerator, S02 monitoring data provide sufficient sulfur
emission data and TRS monitors are not required in such cases. It would
be only under such cases in which a TRS monitor would be used in addition
to an S02 monitor on a unit employing a properly operated incinerator
that the calculated efficiency would increase by only about 0.02 percent.
The Agency agrees that the additional accuracy provided by a TRS monitor
on a system with a properly operated incinerator is not warranted.
Comment: The commenter (IV-D-18) recommended that §60.645(a)(l) be
deleted. No reason for this recommendation was provided.
Response: Commenter is referring to the reference method (Method 1)
for velocity traverse points selection. The volumetric flow rate is
necessary to calculate the sulfur mass rate. Volumetric flow rate is
calculated using the average velocity in the duct or stack. The average
velocity is determined by Reference Method 2. Since this procedure is
based on the use of a pitot tube that measures velocity at point locations
in the flow cross section, multiple measurement points are necessary to
determine the average velocity for the flow area. Method 1 is a formal
procedure for selecting these measurement points.
Comment: Commenter IV-D-30 claimed that there was no real reason
to perform Method 6 (S02) and Method 16A (TRS) separately for oxidation
type control systems because the two results are summed to determine •
sulfur emissions. Specifically, Method 6 could be utilized with the
addition of the combustion tube apparatus as described in Method 16A.
This procedure would result in all sulfur species being oxidized and
collected while reducing the testing time by 50 percent.
Response: Method 6 and Method ISA must be performed separately for
systems using an incinerator because the standards require the
determination of the ratio of S02 to total sulfur for the purpose of
ensuring complete oxidation of sulfur compounds to S02. The commenter's
suggestion that Method 6 be used with the combustion tube apparatus
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described in Method 16A would be appropriate if determination of total
sulfur were the only requirement. However, the Agency has not evaluated
this procedural variation to determine if a combined measurement would
yield equivalent results, and therefore, there is no basis to promulgate
a reference test method in Appendix A using this procedure. An owner or
operator may request that the Administrator approve the use of this
alternate technique under the provisions of 60.8(b) if sufficient
supporting information is provided to demonstrate the adequacy of the
proposed technique for determining compliance. At this time, the Agency
does not regard the requirement for a Method 6 and a Method 16A test for
these one-time performance test requirements as excessive.
Comment: The commenter (IV-D-30) claimed that Performance
Specification #2 of the general NSPS rules for continuous S02 monitors
is applicable only to instruments which generate concentration values.
Since the proposed standard requires continuous monitoring of mass
emission rates, the commenter claimed that an adjustment to the
performance specifications procedures is needed to account for error in
continuous determination of flow rate and specifically, the relative
accuracy specification should be modified. The commenter recommended
that the Agency review the issue to eliminate any inconsistency between
the type of continuous monitor required by the proposed NSPS and the
criteria of Performance Specification #2.
Response: The Agency recognizes that Performance Specification #2
pertains to measurement results expressed as concentration values.
However, when S02 concentration measurements are made in conjunction
with a properly installed, operated, and calibrated stack gas flow
meter, the relative accuracy requirements can be met. It should be
noted, however, that the instrument must be operated within its proper
design range. Significant errors can result from the operation of a
flow meter outside its specified range. The Agency assumes that
appropriate instrumentation is being used. Therefore, .no adjustment
will be made to Performance Specification #2 to accommodate these
standards.
Comment: The commenter (IV-D-18) requested that a minimum of
fifteen 1-hour averages be used to compute each 24-hour average emission
rate "E," instead of nine 1-hour averages to compute a 12-hour average.
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Response: The requirement for nine 1-hour averages to compute a
12-hour average reflects a 75 percent data capture requirement. The EPA
requirement is at least one data point per 15 minutes and two 15-minute
points for calculation of a 1-hour average. Experience indicates that
this is reasonable for S02 monitors and allows sufficient time for
adjustments to the monitor or other operations that preclude 100 percent
data availability. The standards have been revised to allow calculation
of recovery efficiency on a 24-hour basis. In keeping with the 75 percent
data capture requirement, 18 1-hour averages will be required to compute
each 24-hour average.
Comment: The commenter (IV-D-18) recommended that requirements of
§60.646(b)(5) be waived when instrument malfunctions limit the sulfur
emission data collection, provided the owner/operator makes reasonable
efforts to maintain and operate the monitoring instrument.
Response: Requirements of §60.646(b)(5) cannot be waived but data
for periods of instrument malfunction should be noted as not available
for recordkeeping purposes. Sections 60.7(b) and (c)(2) of the General
Provisions provide for such periods of breakdown or repair and require
identification of the malfunction nature, cause, and corrective action
taken.
Comment: The commenter (IV-D-18) recommended deleting §60.647(b)(2)
and inserting the statement, "Any 24-hour period during which the flare
or incinerator is operated less than 12 hours."
Response: The Agency disagrees with the commenter's recommendation
to delete §60.647(b)(2) because the provision is necessary to ensure
complete oxidation of sulfur compounds to S02. However, in response to
other comments, this section has been revised to replace the temperature
requirement with an alternate provision to ensure oxidation of sulfur
compounds to S02.
The commenter1s proposed definition of excess emissions would make
it possible for a sulfur plant to operate without incineration or flaring
for up to half the time without a report of excess emissions. The
Agency rejects this suggestion.
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2.13 RECORDKEEPING AND REPORTING REQUIREMENTS
Comment: Two commenters (IV-F-2 and IV-D-18) suggested annual or
semiannual reporting instead of quarterly reporting to relieve what are,
in their opinion, excessive reporting requirements.
Comment: The commenter (IV-D-18) claimed that the monitoring,
recordkeeping, and reporting requirements were excessive for small to
medium sized plants and suggested that requirements could be reduced and
still achieve S02 emission reductions.
Specifically, the commenter recommended that:
1. Plants handling less than 20 LT/D be exempted from all
requirements except in-house records to justify the exemption.
2. Plants between 20 and 100 LT/D should be required to maintain
in-house records of daily sulfur production, quarterly gas
analysis, and annual calculation of sulfur recovery efficiency.
3. Plants larger than 100 LT/D should be required to record daily
sulfur production, quarterly gas analysis, and calculation of
sulfur recovery efficiency, and should report these data to
the Administrator annually. The commenter also stated that
continuous monitoring may be required for such facilities.
Comment: The commenter (IV-D-22) requested that facilities less
than 50 LT/D should be exempt from continuous monitoring and recordkeeping
requirements because these plants are operated with very small staffs
and the recordkeeping and reporting would be burdensome with little
benefit to the environment.
Comment: The commenter (IV-D-28) claimed that the recordkeeping
and reporting requirements of the standard were excessive and estimated
they would require 160 man-days per year per plant.
Comment: Three commenters (IV-D-16, IV-D-22, and IV-D-28) claimed
that many small remotely located plants are staffed less than 12 hours
per day. The commenter stated that recordkeeping, reporting, and
instrumentation requirements are all excessive and may cause many small
fields to be uneconomical to produce.
Response: The reporting requirements outlined in the proposed
standards are not considered by the Agency to be excessive. During the
first 3 years of implementation, the average industry-wide labor burden
was estimated to be 8.4 person-years per year, based on an average of
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12 respondents per year. These labor estimates are considered by the
Agency to be reasonable. However, in response to the concerns presented
by representatives of small remote plants, the standards have been
revised to require sulfur measurements every 24 hours instead of the
12-hour frequency required in the proposed standards.
Also, the quarterly period for reporting excess emissions has been
revised. These reports will now be required semi annually instead of
quarterly.
Comment: The commenter (IV-D-9) stated that plants with design
capacities less than 1 LT/D should be exempted from recordkeeping and
reporting requirements which require that an analysis of the facility's
design capacity be retained for the life of the plant. The commenter
contended that the requirements were too stringent for small, isolated
plants and that the document may easily be misplaced during the facility's
lifetime. Another commenter (IV-D-18) requested that the portion of the
regulation [60.647(c)] dealing with recordkeeping and reporting
requirements for plants less than 1 LT/D be deleted.
Response: Documenting the design capacity of a plant is required
to determine the applicability of the standards. If the design capacity
is less than 2 LT/D, then no further analyses are required. This single
determination has not been found by the Agency to be excessive. Proper
business procedures should allow for the safekeeping of this and other
company records. Note also that these records need not be kept at the
plant site.
The average industry-wide labor burden for recordkeeping and
reporting requirements for plants with design capacities less than
2 LT/D during the first 3 years of implementation of the standards was
estimated to be 18 person-hours per year, based on an average of
6 respondents per year. These estimates and burdens are regarded as
reasonable by the Agency.
Comment: The commenter (IV-D-17) claimed that the data gathering
and recordkeeping requirements of the standard were extensive and that
enforcement efforts using a large volume of past records would lack the
clarity and relevance provided by a recent stack emission test. For
this reason, the commenter favored an emission rate standard for
enforcement purposes. The commenter stated that recordkeeping and
2-88
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calculated performance were useful tools in indicating the need for
stack testing. The commenter claimed that the records were to provide
demonstration of compliance.
Response: The basic concern raised by the commenter is that data
gathering and recordkeeping requirements associated with the continuous
emissions monitoring requirements in §60.646 are excessive and
inappropriate for determining compliance with the standard. The commenter
has misinterpreted the purpose for the monitoring and associated
recordkeeping requirements. These provisions are not for determining
compliance but rather they provide an indication of whether or not an
affected facility is being properly maintained and operated on a
continuous basis. These data assist enforcement officials in the decision
of whether or not a performance test is necessary to determine compliance.
The Agency is not requiring performance tests on a periodic schedule
because of cost considerations. Rather, the Agency established what is
believed to be the minimum monitoring and recordkeeping requirements
needed to ensure proper operation and maintenance and to provide
enforcement agencies with an indication of compliance status.
The allowable emission rate format favored by the commenter was
considered in the development of the standard, as discussed in the
preamble (49 FR 2663). Allowable emission or mass emission rate format
is expressed in pounds per hour and parts per million by volume that
apply uniformly to all facilities within a range of sulfur feed rates
(sizes) and H2S concentrations. If the allowable emission rate format
was used, the standards would have to specify numerous mass rate limits
corresponding to efficiencies achievable with BDT. Either of these
formats would establish required emission reduction efficiencies
applicable to various plant sizes. Large plants would have to achieve
high reduction efficiencies while smaller plants within the same range
would have to achieve increasingly lower reduction efficiencies to meet
the same limit. This would present a situation in which smaller plants
would not have to install BDT or larger plants would require technologies
with performance capabilities exceeding those of BDT.
Because the format of the standard needs to reflect the variation
in the emission reduction efficiencies achievable by the selected BDT,
the proposed standard takes the form of an equation that calculates the
2-89
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required emission reduction efficiency (or sulfur recovery efficiency)
for each specific plant type based on the two characteristics of the
acid gas (i.e., the mass flow rate of acid gas and the concentration of
H2S in the acid gas). The equation calculates required emission reduction
efficiencies that closely match the efficiencies achievable with BDT.
The result is a standard that ensures the application and the proper
operation of BDT at new facilities. For this reason, the Agency regards
the reduction efficiency format as the most appropriate for the standard.
Comment: The commenter (IV-D-23) recommended that only one quarterly
report be submitted either to a State or Federal agency for compliance
with all air pollution regulatory requirements including PSD, NSPS, and
any other applicable regulations.
Response: If, in delegating enforcement authority to a particular
State under Section lll(c) of the Act, EPA approves the reporting
requirements adopted by such State, then the affected sources within the
State may comply with the State requirements in lieu of the Federal
requirements.
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2.14 DIFFERENCE IN STATE AND NSPS REQUIREMENTS
Comment: The commenter (IV-F-4) expressed concern over the
differences in conversion efficiencies required by the Texas Air Control
Board and those of the proposed regulation and the possible net increase
in S02 emissions that may result from NSPS promulgation and enforcement.
Another commenter (IV-D-17) stated that the NSPS appeared to be more
lenient than the current Texas Air Control Board appraisal of best
available control technology. The first commenter provided plant-
specific data on 14 cases that indicated that differences in required
conversion efficiencies would be generally in the 2 to 4 percent range.
One particular case had a 20 percent difference in conversion efficiency.
An overall increase in S02 emissions in that State would total 22,800 tons
per year, if the proposed standards are adopted, according to Texas Air
Control Board estimates.
Response: The required sulfur recovery efficiencies in the standards
are designed to be applicable nationwide. Federal regulation requirements
must be achievable by all affected facilities, irrespective of local air
quality conditions. Standards with a degree of uniformity are needed to
avoid situations where some States may attract industries by relaxing
standards relative to other States. The NSPS serve as a minimum
requirement to reduce emissions from each designated source category on
a nationwide basis and are developed considering factors such as
incremental cost effectiveness.
Some States may require emission reductions more stringent than
NSPS in order to meet that State's air quality goals. Section 116 of
the Act permits these States to establish more stringent standards. As
a result, factors considered in NSPS development (e.g., incremental cost
effectiveness) may be different for the State standards.
Comment: The commenter (IV-D-7) expressed his opinion that the
proposed standards are too lenient, given the wide range of available
sulfur control technologies. The commenter recommended adoption of
Regulatory Alternative IV or, preferably, Alternative V instead of III
as in the proposed standards. The commenter stated that technologies
similar to Alternative V are currently required in Michigan and are
economically feasible.
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Response: The Agency selected the regulatory alternative based
primarily on incremental cost effectiveness (i.e., additional emission
reduction). The cost effectiveness associated with moving from
Regulatory Alternative III to IV was judged to be unreasonably high for
NSPS. In addition, the economic impact analysis indicated a potential
for adverse economic effects on some small plants under Alternatives IV
and V.
The NSPS are nationwide standards applicable to the broad spectrum
of conditions that can be found at sulfur recovery facilities in
locations across the country. The NSPS do not constrain State and local
regulatory officials from establishing more stringent requirements based
on the specific natural gas processing plant or environmental conditions
that may be found in a particular region. Indeed, many facilities will
be subject to the requirements of "best available control technology"
(BACT) or "lowest achievable emission rate" (LAER) under Parts C and D
of the Act. BACT and LAER must be as stringent as, and may be more
stringent than, the NSPS. The Administrator is aware of existing
facilities meeting more stringent requirements and expects similar
situations to arise in the future. Even so, these situations are
dependent on regional or site-specific factors that cannot be accounted
for in national standards. For these reasons, the Agency continues to
believe that Regulatory Alternative III is the most appropriate basis
for the NSPS.
Comment: The commenter (IV-D-8) stated that meaningful national
emissions standards cannot be structured to account for the wide
nationwide variations in plant treating volumes and acid gas ratios,
both of which affect the selection of appropriate control technology.
The commenter believes that individual State programs are more capable
of handling these variations on a case-by-case basis, especially for
small plants.
Response: The EPA agrees that individual State programs are more
capable of handling case-specific regulatory concerns than are the NSPS.
It is not the intention of EPA to preempt these State regulatory
functions. Rather, it is to provide national standards to provide a
minimum uniform level of control.
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The EPA disagrees with the commenter's contention that meaningful
standards cannot be structured to account for the wide variations in
sour natural gas plant characteristics. The proposed standards are
based on an analysis of the entire range of sulfur feed rates and the
percent H2S in the acid gas expected to be found in domestic sour gas
processing facilities. Moreover, the efficiency equations within the
standards were evaluated to determine their effect over the same ranges
of expected facility characteristics. In no instance were the standards
found to be unattainable or result in any unreasonable cost or economic
impacts. Consequently, EPA is retaining the level and format of the
proposed standards.
Comment: Two commenters (IV-D-7 and IV-D-15) stated that the
proposed NSPS with its 1 LT/D plant size cutoff would encourage the
building of smaller, less efficient or uncontrolled plants in lieu of
larger, centralized plants to avoid control requirements. One commenter
(IV-D-7) cited examples of small plant proliferation in the State of
Michigan in response to a PSD cutoff as the basis for his concern. The
commenter believes that the 1 LT/D cutoff in the proposed standard may
lead to the same problem.
Response: The decision for the proposed plant size cutoff of
1 LT/D was based on cost effectiveness. (Since proposal, a revised
analysis, incorporating updated assumptions, established the cutoff at
2 LT/D, using the same cost-effectiveness criterion.)
The Agency shares the commenter's concern that small plant (<2 LT/D)
proliferation may occur as a means of circumventing the standards. This
is a possibility with almost all cutoffs. However, the cutoff cannot be
raised since it would result in a cost-effectiveness value judged by the
Administrator to be unreasonable for plants covered by this NSPS. To
encourage the construction of larger, more efficient plants, State
agencies, with the authority to require more stringent control than
required by the NSPS and to consider case-by-case situations, may require
plants with sulfur feed rates <2 LT/D to reduce S02 emissions.
Comment: Commenter IV-D-15 recommended that the sulfur recovery
efficiencies required for large plants be reduced. The commenter pointed
out that the proposed standards, which require higher sulfur recovery
efficiencies for large plants than for small plants, limit the economic
2-93
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incentive to construct large plants. The State of Michigan Department
of Natural Resources, which regulates the commenter's plants, has
encouraged natural gas producers to form centralized cooperatives and
the commenter believes that the proposed Federal regulation may cause
the number of small facilities to increase and, therefore, cause increased
environmental impacts. He recommended that a low recovery efficiency be
required regardless of plant size to eliminate the inequity and maintain
the incentive to construct large plants. The commenter claimed that
such an action would not cause a net increase in SOp emissions, but
would eliminate the deleterious effects of multiple small plants being
built in close proximity to one another.
Response: The purpose of NSPS is not to encourage or discourage
the construction of certain sized plants. The standards are intended to
be economically neutral by assuring that no adverse economic impacts
would result. The standards in this case may have the effect of
eliminating or limiting the economic incentive which may currently exist
in Michigan to construct larger, centralized facilities. However, the
economies of scale offered by larger plants may still provide an incentive
to build larger facilities.
.The Agency's major objection to the commenter's suggestion is that
a uniformly low reduction efficiency would not reflect BDT for larger
units and would, therefore, be inconsistent with Section 111 of the
Clean Air Act. The Act requires the Agency to base the standards on BDT
for each category of sources regulated. If a low recovery efficiency is
promulgated which larger plants could easily achieve, the standards
would not reflect BDT for these larger units since they are capable of
achieving higher efficiencies at a reasonable cost.
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2.15 MISCELLANEOUS COMMENTS
Comment: The commenter (IV-F-2) affirmed that the sulfur recovery
levels set by Regulatory Alternative III are a practical basis for
regulating the gas industry. In addition, Alternatives IV, V, and VI
are believed by the commenter to be too stringent.
Response: No response is necessary.
Comment: In response to an EPA inquiry in the proposal preamble
concerning 250 to 1,000 LT/D plants with H2S concentrations less than
50 mole percent, the commenter (IV-D-13) reported that his company
(Exxon) had one such plant in operation and projected installation of
two others. The commenter claimed that sulfur recovery facilities for
these plants would be generally consistent with those in the proposed
standards, but the testing, monitoring, and reporting requirements and
costs would not be required in the absence of the NSPS.
Response: No response is necessary.
Comment: The commenter (IV-D-21) stated his support of comments
presented in Docket Entries IV-F-5 and IV-D-29 and wished to express
concurrence with those comments.
Response: No response is necessary.
Comment: The commenter (IV-D-18) questioned the statement in the
preamble (49 FR 2658) that there "would be no significant impact on
solid waste disposal," and claimed that the statement could not be
verified at this time. The commenter stated that there likely will be
significant cost, permitting, transportation, and other impacts associated
with sulfur disposal at small facilities.
Response: The Agency's determination of "no significant impact on
solid waste disposal" was based on results of disposal cost analysis and
the classification under RCRA regulations of waste by-product sulfur as
nonhazardous (II-B-41).
The $0.25/Mg/mile sulfur disposal cost considered for small plants
in the cost analysis (BID, Chapter 8, Table 8-3) is believed to be
reasonably representative of costs incurred by small plant operators.
The $25/Mg sulfur disposal cost factor assumes an average 100 mile
transport of sulfur prior to disposal and was based on information
obtained from the Ralph M. Parsons Company.
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Comment: The commenter (IV-D-18) recommended changing the
designation of §60.646(c) and (d) to (b)(7) and (b)(8), respectively,
with no change in wording.
Response: In response to this and other comments, §60.646 has been
revised.
Comment: The commenter (IV-D-25) claimed that the reasoning used
to justify the proposed standard was faulty and that the Agency confused
the crude oil refining industry with the natural gas processing industry.
The commenter stated differences in the two industries concerning location.
For example, the commenter stated that a refinery is usually permanently
located near transportation facilities such as waterways or pipelines to
ensure a constant supply of crude oil. A gas processing plant, however,
is usually skid mounted and located at or near the gas field and the
life of the plant is determined by that of the gas field. Therefore,
the commenter stated that refineries and chemical plants are usually
located in highly industrialized areas with large populations and a
typical gas plant is located at the gas field site in remote areas away
from any type of large population base.
The commenter also stated that gas plants and any sulfur removal
equipment is designed and sized based on life expectancy and size of the
gas field. The commenter claimed that field life was usually 12 years.
Refineries, however, are sized and designed based on marketing require-
ments for the various products at the refinery and the type of crude to
be refined. The commenter stated that most refineries have long term
crude oil supply contracts and that feed to the facility is constant.
Response: The Agency recognizes the differences in the crude oil
refining industry and the natural gas processing industry. Each of the
characteristics of natural gas sulfur recovery plants identified by the
commenter has been taken into account, to the extent possible, in the
analyses and rationale supporting the standards. The reasoning used to
justify the standards is not regarded as faulty. The fact that the
source is located away from population centers is not relevant because
502 is a long-range pollutant.
In its evaluation of comments received on the proposed standards,
the Agency carefully assessed the concerns of remote facilities. In
response to those concerns, the standards have been revised to require
2-96
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sulfur measurements on a 24-hour, rather than a 12-hour, basis. Also,
for smaller plants, a 12-year field life was used in the revised economic
impact analysis.
Comment: The commenter (IV-D-29) questioned paragraph 60.646(b)(3)
of the standard, which he reported required a continuous S02 monitor if
the emission reduction efficiency standards in paragraphs 60.642(a)
or (b) are to be achieved using an oxidation control system (thermal
incinerator) or a reduction control system (SCOT tail gas unit) followed
by an incinerator. The commenter stated that thermal incinerators will
not achieve sulfur reduction but convert H2S to S02.
Response: The section in question was not meant to imply that
incineration is a sulfur recovery process. The purpose of the incinerator
is the oxidation of H2S to S02; the SCOT unit provides tail gas cleanup.
Comment: The commenter (IV-D-30) recommended that the Agency give
serious thought to withdrawing the proposed NSPS because in the
commenter1s opinion, the rule does not meet the legislative criteria of
Sections lll(f)(2)(A) through (C) of the Act.
Response: The proposed rule meets the criteria set forth in the
Act. The Administrator is required to consider: (a) the quantity of
air pollutant emissions that each category will emit or will be designed
to emit; (b) the extent to which each such pollutant may reasonably be
anticipated to endanger public health or welfare; and (c) the mobility
and competitive nature of each such category of sources and the consequent
need for nationally applicable new source standards of performance
[Sections lll(f)(2)(A) through (C)].
Onshore natural gas processing has been determined to be a major
source of S02 emissions. The natural gas processing industry emits an
estimated 250,000 megagrams per year of sulfur dioxide (Volume I BID,
pg. 3-9). A typical 5 LT/D plant emits about 3,500 Mg of S02 per year.
The Administrator has determined that emissions from this source
contribute significantly to air pollution that may reasonably be
anticipated to endanger public health or welfare. This is reflected in
the EPA priority list (40 CFR 60.16 amended at 47 FR 951, January 8,
1982) in which the natural gas producing industry ranks 29th out of
59 source categories. (See Section 2.1, pg. 2-1, of this document for a
detailed discussion of this topic.)
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Comment: The commenter (IV-D-31) claimed that older plants do not
have the incentive to decrease emissions when repairs exceed 50 percent
because it would trigger NSPS. This all-or-nothing philosophy often
results in nothing.
Response: No reconstructions were projected in this proposed
standard because of its application to sweetening units and sweetening
units followed by sulfur recovery units.
"Reconstructions" were not projected because no situations in the
industry are anticipated in which the replacement costs would exceed
50 percent of the cost of an entirely new facility.
Comment: The commenter (IV-D-31) stated that specific mention of a
licensed process (e.g., Selectox, SCOT, Sulfreen, etc.) is not desirable
because it makes new processes harder to get approved. Instead, Table 6-1
in the background information document should give percentage recovery
required and then list the acceptable percentage recovery for all
currently proven processes.
Response: In developing the basis for the standard, the Agency
surveyed all available demonstrated and emerging technologies applicable
to S02 emissions from natural gas processing. Following the survey,
certain of these technologies were ultimately selected as representative
of BDT. The BDT classification does not imply that a specified process
must be applied. The plant operator may select any control technology
which meets the emission reduction efficiency required by the standard.
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Appendix A: Revised Economic Impact Analysis
A.I. Introduction
The NSPS will raise production costs for natural gas wells producing
sour gas. The economic impact on these wells will differ depending on the
size of the well, the gas flow, the percent of H2$ in sour gas, and the
percent of the acid gas containing H2S. Other parameters such as the price
of natural gas and the price of recovered elemental sulfur also affect the
economic well being of natural gas wells but in a fairly consistent manner
across well sizes and gas characteristics. The objective of this revised
economic analysis was to identify by size and gas characteristics any sour
natural gas wells to be built or reconstructed in the future, that will
incur an adverse economic impact due to the NSPS.
As the results of this analysis show, for new plants likely to be
built in the future, the NSPS does not impose adverse economic impacts and
therefore will not force the cancellation or postponement of construction
of any planned onshore gas processing facilities. Consequently, reductions
in output levels are expected to be very slight and are not expected to
encourage significantly higher gas prices, or any other disruption of the
natural gas industry.
Appendix A is organized as follows. The general methodology used to
conduct the economic analysis is discussed in the next section of the
appendix, followed by a description of the data requirements in Section A.3.
Miscellaneous program variables necessary to run the discounted cash flow
model are explained in Section A.4. The discounted cash flow analysis
is discussed in Section A.5 with results described and examples presented
in Section A.6.
A.2. Methodology
The revised economic analysis has been conducted because several key
data inputs have changed since the original analysis was completed and
because it was learned during the comment period that sweetening costs were
erroneously omitted from the original analysis. The major data revisions
are as follows:
1. In the original analysis the price of natural gas was assumed to
be S4.8U/MCF in 1987 (in 1980 dollars). This price assumed
deregulation in 198b. In the revised analysis deregulation is
-------
also assumed to occur but a different price forecast and year
dollars (1984) have been used. The price of natural gas is
assumed to increase at a constant rate until 1994 as follows:
(1984$/MCF)
1985 $3.88
1986 4.06
1987 4.25
1988 4.44
1989 4.64
199U 4.86
1991 5.08
1992 5.32
1993 5.56
1994 5.82
In the original analysis a price of $100/ton was assumed for
recovered sulfur. The price has been lowered to $77/ton based on
comments received. No sulfur recovery credits are assumed for
plants less than 5 LT/0 sulfur intake.
In the original study a real cost of capital of 2% was used. In
the revised analysis a real cost of capital of 6% is used based
on a prime rate of 11% and an inflation rate of 5%.
Capacity utilization for the purposes of generating revenues from
sweet gas sales and sulfur sales is assumed to be 75%.
The original analysis assumed a well life and equipment life of
20 years for all size plants. In the revised analysis the well
life for plants less than or equal to 20 LT/D is assumed to be 12
years. Equipment life is assumed to be 20 years and a salvage
value is therefore included. The salvage value is calculated
based on straight line depreciation (i.e., after the 12th year,
40% of equipment value is assumed to remain). The salvage value
is treated as a cash inflow at the end of the 12th year. For
plants greater than 20 LT/D, tne well life and equipment life are
both assumed to be 20 years.
No severance tax was assumed in tne original study. In this
revised report, severance tax has been considered by the discounted
A-2
-------
cash flow model as a five percent reduction in revenue. The five
percent represents an average across all natural gas producing
states.1
As stated earlier, the objective of this revised analysis is to identify
by size and gas characteristics those future plants that will be adversely
affected by the NSPS. This is achieved by conducting a net present value
(NPV) analysis under both the baseline and Regulatory Alternative III. For
a review of the controls to be imposed under Regulatory Alternative III see
BID Table 6-1. The NPV analysis calculates the present value of all cash
flows associated with a project. If the resulting value is positive, the
project is economically feasible because cash inflows exceed cash outlays.
If the net present value is negative the project is not economically
feasible.
A.3. Data Requirements
The first step in the' revised analysis was to identify the range of
potential new plants by size and gas characteristics. Joint probability
distributions considering size of plant, ^S in the wellhead gas and HgS
in the acid gas were created based on historical data. The result was the
identification of all plants by size, h^S in wellhead gas and H£S in acid
gas that have a positive probability of being built in the future. Tables
A.I through A.3 form the basis for these probability.tables. Table A.I
shows the various probabilities of plants within different size ranges
having H2S in the acid gas within the specified ranges. Table A.2 shows
the various probabilities of plants within different size ranges having
H2$ in the sour gas within the specified ranges. Table A.3 shows the
probabilities of sour gas treating facilities being within the specified
size ranges. The combination of these three tables forms the basis for
Tables A.4 through A.10. These tables represent the probabilities of
future plants being within the different size ranges and having the
various gas characteristics stated.
This is the realm of plants that are of interest to us in determining
economic impacts of the NSPS. Plants that are not likely to be
built will obviously not be affected by the NSPS.
Cost Analysis
Sulfur credits are calculated and shown in Table A.11 for the baseline
scenario. Sulfur credits are in 1984 dollars and are calculated based on
A-3
-------
an average freight on board recovered sulfur price of $77/ton. See Docket
entry IV-8-3. Sulfur credits are calculated assuming a capacity utilization
of 7b%. In the baseline it is assumed that there are no controls for those
plants 7 LT/D and less. See BID Table 6-1 for baseline control strategies
for plants greater than 7 LT/D. Production costs are included in the
capital and annual costs. Working capital (i.e., inventories, cash,
accounts receivables, etc.) is calculated at 2U% of capital costs based on
a survey of oil and gas producing companies made by Chase Manhattan between
1977 and 1981.2 Table A.12 shows the same types of costs for Regulatory
Alternative III, (i.e., the NSPS).
Revenues
The volume of sweet gas for sale from each plant likely to be built in
the future was calculated based on the size of the plant and the gas
characteristics. As can be seen in Table A.13., this calculation excludes
the amount of sweet gas that is consumed in the sweetening plant operation.
Tne volumes reflected in Table A.13 are based on 1UU% capacity utilization.
These volumes have therefore been reduced by 25% to reflect the current
assumption of 75& capacity utilization. Revenues from sweet gas sales were
calculated for each year 1985-1999 by multiplying the volume of sweet gas
(at 75% capacity utilization) for sale by the appropriate price of wellhead
natural gas. See the natural gas prices, 1985-1994, on page A.2. As noted
earlier, revenues from sweet gas sales were further reduced an additional
five percent to reflect severance taxes. The projected average natural
gas prices were generated from the hydrocarbon supply model developed by
Energy and Environmental Analysis, Inc. and referenced in their July 1984
report entitled "Regional Forecasts of Industrial Residual Fuel Oil and
Natural Gas Prices" (Docket entry IV-A-4). These prices represent the
marginal price for new gas only and assume deregulation of natural gas in 1985,
A.4. Other Program Variables
In order to use a discounted cash flow model to perform the net present
value analysis, several other program variables needed to be specified. The
ratio of debt to total assets has not been revised from the original analysis.
A bU% debt to total assets ratio is used based on Table 9-14 of the original
economic impact analysis. See page 9-32 of the proposal SID. The nominal
rate of interest of 11% was selected based on the current prime rate. The
nominal rate of return on equity for this industry is estimated to ne 12.5«.
A-4
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TABLE A.I.
FACILITY SIZE MOBABILITY OF * FACILITY KITH!* K 6IYEN SIZE RAXSE HAVIW A IH2S IN*TH£
t«6/0 SULFUR) DCIO MS IITHK Tffi STCCIFlEt DMSES
ZH2S IK THE ACID 64S
W. 00001
(0.0402
0.00421-0.0003
0.00011-0.0004
4.40041-4.0005
0.00051-0.0006
4.00041-0.0007
0.00071-0.0008
0.00081-0.0009
0.00091-0.0010
0.0011-0.002
0.0021-0.005
0.0031-0. 004
0.0041-0.005
0.0051-0.004
0.0061-0.007
0.0071-0.008
4.0081-0.009
0.009I-O.OIO
o.on-o.02
0.021-0.03
0.031-0.04
0.041-0. OS
0.05!-0.0i
0.061-0.07
0.071-0.08
0.081-0.09
0.091-0,10
0.11-1.0
1.1-2.0
2.1-3.0
3.1-4.0
4.1-5.0
5.1-10.0
10.1-20.0
20.1-30.0
30.1-40.0
40.1-50.0
50.1-40.0
40.1-70.0
70.1-80.0
80.1-90.0
90.1-100.0
100.1-110.0
110.1-120.0
120.1-130.0
130.1-140.0
140.1-150.0
150.1-160.0
160.1-170.0
170. -180.0
ISO. -190.0
190. -200.0
200. -300.0
300. -500.0
500.1-750.0
750.1-1000.0
>1 000.1
(0.00001 <0.
MKE 0.
4.
0.
4.
0.
0.
0.
0001
1700
2400
3100
2400
1900
1900
1700
0.2100
0.
0.
0.
0.
0.
0.
0.
0.
0.
0.
0.
0.
0.
0.
0.
0.
0.
0.
1200
1000
1500
0900
0700
OBOO
0500
0400
0400
1000
0500
0060
ooao
0140
0420
0090
0004
0004
W.OOOi
(0.001
0.8300
0.7400
O.i900
0.5200
0.6200
0.4300
0.3400
0.2700
0.5100
0.4400
0.3200
0.6100
0.6600
0.4300
0.4300
0.3900
0.2600
0.2100
0.1100
0.1300
0.3300
0.3050
0.4590
0.1860
0.0320
0.0090
/».»«!
(0.01
0.2500
0.2000
0.3800
0.4900
0.5200
0.3700
0.4400
0.5300
0.2900
0.2800
0.4900
0.2400
0.2600
0.3100
0.4100
0.4400
0.3100
0.3200
0.2910
0.2190
0.1770
0.0730
0.2120
0.1150
0.1750
0.0880
0.0090
)O.OI M.02
(0.02 (0.05
0.1700 0.1000
0.1800 0.1000
0.2200 0.1200
0.1800 0.0600
0.1200 0.1000
0.1500 0.0850
0.1400 0.0800
0.1660 0.0970
0.1250 0.0680
0.1770 0.1500
0.0900 0.4040
4.0760 0.0480
0.0330 0.0130
0.0500 0.0190
0.0430 0.0180
0.0100 0.0110
0.0784
>0.05
(0.125
0.0100
0.0100
0.0200
0.0200
0.0800
0.0490
0.0500
0.0550
0.0040
0.1260
0.1640
0.2080
0.1230
0.1560
4.1170
0.0500
4.1100
>0.125
(0.20
0.0100
0.0190
0.0600
0.0350
0.0400
0.0430
0.0290
4.1400
0.0580
0.1260
4.5450
0.0830
0.1250
0.1990
4.1560
0.1580
0.1100
0.0580
4.0494
4.0050
0.0010
>0.20
<0.5
0.0060
0.0150
0.0260
0.0180
0.0200
0.0190
0.0140
0.0470
0.1250
0.2040
4.0980
0.3370
0.3780
0.4300
0.4210
0.5120
0.5920
0,5730
0.6170
0.3160
0.5370
0.4700
0.4740
0.4700
0.3000
0.3900
0.3000
0.2100
4.2304
0.1400
0.4700
0.0700
>C.S
(O.B
0.0020
0.0070
0.0010
0.0070
0.0100
0.0070
0.0060
0.0210
0.0440
0.0870
0.0630
0.1430
0.1970
0.2440
0.1790
0.2540
0.2100
0.3050
0.1970
0.5390
0.3430
4.4000
0.4000
0.4000
0.4300
0.4700
0.3200
0.4900
4.4300
0.5300
0.5800
0.4300
0.1200
0
0
0
0
0.
0
0.
0
0.
0
0.
0
0.
0.
0.
0
0.
0
0.
0
0.
0.
0.
0.
0.
0.
0.
0.
0.
0.
0.
>o.s
(1.0
0003
0005
0005
0020
0050
0010
0020
0080
0100
0300
0110
0370
0510
0430
0560
0760
OS80
0640
1370 .
1410
1190
1300
1300
1300
2700
1400
3800
3000
2900
3300
3500
0.5000
0.
1.
1.
1.
1.
3800
0000
0000
0000
0000
A-5
-------
TABLE A.2.
HCJLJTT SIZE rtOMBILITT
OF « FACILITY HITHIK « 6IVEX SIZE RMSE HAVtNS A IH2S
in THE
(K/I SULFUS) SOUR MS KITHII THE SPECIFIES UMSES
„ _WJS 1» TK StIK ««„ . . ._.. .
(0.0400*4 W
OOOviMXi.OOWl X.0001 M.041 XJ.01 J4.02
rt.05
(0.00001 (0.0001 <0.001 (0.01 (0.02 (O.OS (0.122
(».0002
0.00021-0.0003
O.OOOJI -0.0004
0.00041-0.0005
I.M031-4.MM
O.OOM1 -0.0007
0.00071-0.0008
0.00081-0.0009
4.00491-4.0010
.0011-0.002
.0021-0.00:
.0031-4.004
.0941-0.005
.0051-0.006
.0061-0.007
.0071-0.006
.0081-0.009
.0091-0.010
0.011-0.02
.021-0.0:
.0:1-0.04
.041-0.0!
.Oil -0.04
.061-0.07
.071-4.08
.081-0.09
.091-0. /0
.0000
.0000
•0000
.0040
.0400
>4.125 >4.20
(0.20 (O.S
.8500 8.1500
.9400 0.0400
.8104
.4*04
.2400
.3400
.4104
.2804
.3900
.3044
.3100
.3200
.2000
.1800
.0900
.1600
.1344
.1104
.1900
.COO
.4400
.1540
.2600
.2500
.3500
.1800
.2800
.2540
.1800
.2500
.2100
.2200
.2204
.2040
.0700 0.1300 (
.2MO
.3200
.2604 4.0400
.1900 O.OWO
.3900
.1200
.3704
.2200
.2904
.4404
.MOO
.4800
.3000
.3400
.MOO
.2700
.0700 4.1440 0.2600
0.11-1.0
1.1-2.0
2.1-J.O
J.I-4.0
4.1-5.0
3.1-10.0
10.1-20.0
20.1-W.O
M. 1-40.0
40.1-50.0
54.1-60.0
tO. 1-70.0
70.1-80.0
10.1-W.O
TO. '100.0
100. -110.0
110. -120.0
120. -134.
130. -140.
140. -ISO.
ISO. -160.
1M. -170.
170. -180.0
IN. -194.0
190. -200.0
200. -300. 0
100.1-900.0
SOO. 1-750.0
7SO.M044.0
>I000.1
(
.2000
.0600
.0800
.1240
.1200
.1000
.1400
.1600
.1600
.1900
.1904
.2000
.4400
.4300
.4840
.4100
.1700
.2100
.1(00
.1700
.0700
.0104
.0500
.0104
.0500
.0400
.0600
.0300
.0500
.0700
.0600
.1304
.1000
.1100
.0900
.1044
.3204
.4900 0.0700 0.0400
.5200 0.1100 0.0704
.6104 .UOO 0.0500
.6100 .1340 0.0800
.5640 .1844 0.0704
.4400 .2200 0.2204
.POO .2800 0.2600
.3300 .2900 0.2600
.2500 .2700 0.3200
.2040 .MOO 0.2804
.1004 .3700 0.2800
.2400 O.SOO
0.4704
0.2400
0.4700
0.3300
0.3200
O.iWO
0.2304
0.1100
—
.0200
.0400
.0800
.1000
.1440
.1900
.2000
.3600
.4400
.2800
.4800
.4600
.5500
.5200
.4JOO
.6700
.7540
.6000
.7540
1.6044
1.9104
.0200
.0200
.0200
.0400
.0400
.0400
.0904
.4800
.0400
.1900
.1204
.1200
.1400
.2200
.2544
.4000
.2504
.4440
.9904
.0044
.5040 0.5000
1.0000
1.0000
A-6
-------
TflRlF A 3 PROBABILITY OF A NEW SOUR
TABLE A.3. |^b^TENING FACILITY
BEING IN A SPECIFIED SIZE
RANGE
MCItm SUE
IN6/D SULFUR) ' SIBOTHED SHOOTffiS MOOTHtD
CUMULATIVE CiMJLATiVE CUIULAT1VE HSCKETE NUK-8 Of
UMBER OF KUflSEfi OF fl!C8A°ILm MOBM111TY PROBABILITY DISCRETE
FACILITIES FACILITIES FACILITIES
(0.0002
0.00021-0.000!
0.00431-4.0004
0.00041-4.0043
0.00051-0.0004
0.00041-0.0007
0.00071-0. 0008
0.00061-0.0009
0.04491-0.0010
0.0011-0.002
0.0021-0.003
0.0031-0.004
0.0041-0.045
0.0051-0.006
0.0061-0.007
0.0071-0.008
0.0081-0. OOf
0.0091-0.010
o.on-4.02
0.021-0.03
0.031-0.04
0.041-0.05
0.051-0.04
0.061-4.07
0.071-0.08
0.081-0.09
0.091-0.10
0.11-1.0
I. 1-2.0
2.1-3.0
3.1-4.0
4.1-5.0
5. -10.0
10. -20.0
20. -30.0
30. -40.0
44. -30.0
50. 1-40.0
44.1-70.0
70.1-BO.O
80. 1-90.0
90.1-100.0
' 140.1-110.0
110.1-120.0
120.1-130.0
130.1-140.0
140.1-150.0
ISO. 1-140.0
140.1-170.0
170.1-180.0
180.1-194.0
190.1-200.0
200.1-300.0
300.1-500.0
340.1-750.0
750.0-1444.0
>I040
1.4444
2.9444
.4004
.4004
.4400
.0400
.4000
.4404
.0000
.0000
.0000
.0000
.0000
.0000
2.0404
9.0000
13.0040
8.4400
5.0044
2.0040
2.0000
3.0040
14.0000
54.0400
12.0000
7.0000
8.0440
7.0000
12.0000
10.0000
21.0040
14.0000
4.0000
1.4404
5.0004
3.0440
1.0004
1.0000
1.0440
1.0000
1.4404
2.0444
2.0044
2.0004
2.0404
1.4444
1.0004
1.0044
1.4444
4.4404
4.0000
9.4000
10.0444
14.4444
23.0444
24.0404
29.0004
34.0040
40.0044
41.0044
43.0000
45.0040
54.0404
67.4000
75.0400
80.0000
82.0400
82.0600
84.0000
87.0000
87.0440
97.0004
147.0040
159.0440
164.0000
174.0000
181.4400
193.0000
203.0000
224.4000
236.0000
244.0004
245.0004
254.0404
213.0040
254.0040
254.0040
255.4040
255.0000
253.0000
256.0000
254.0000
257.0040
257.0044
257.0000
29.0440
264.0400
242.0000
264.0000
264.0444
266.0040
267.0440
4.0437
4.4437
0.4112
4.0154
0.0225
4.0337
0.0375
4.0524
0.0861
4.0974
0.1086
0.1273
0.1498
0.1536
4.1614
4.1485
4.2022
4.2509
0.2809
0.2996
0.3071
4.3071
0.3146
0.3258
4.3258
0.3633
4.5206
• 0.5955
0.6217
0.6517
0.6779
4.7228
0.7603
0.8390
0.8914
4.9139
4.9176
4.9363
4.9476
0.9513
4.9513
0.9551
4.9551
4.9551
0.9588
4.9588
0.9625
4.9625
4.9625
0.9663
4.9738
0.9813
4.9888
4.9888
0.9963
1.4444
4.4437
4.4474
4.0112
4.4154
4.4225
0.0337
4.4375
0.4524
4.0861
0.0974
4.1086
4.1273
4.1498
4.1536
4.1610
0.1685
0.2022
0.2309
4.2809
0.2996
0.3071
0.3109
0.3146
0.3258
4.3446
4.3633
0.5504
0.5955
0.6217
0.6517
4.6779
0.7228
0.7603
0.8390
0.8914
4.9139
4.9176
4.9343
0.9474
0.951J
0.9532
0.9531
4.9543
0.9576
0.9388
0.9607
0.9625
4.9638
0.9650
4.9663
0.9738
0.9813
4.9888
4.9925
4.9963
1.4040
9.4437
0.4032
0.0043
0.4037
0.0075
0.0112
4.4037
4.0150
0.0337
0.0112
0.0112
0.0187
0.0225
0.0037
0.9075
0.0075
0.4337
0.0487
0.0304
4.0187
0.0075
4.4037
0.0037
0.0112
0.0187
4.4187
4.1873
0.0449
0.0262
0.0344
4.4262
0.0449
4.0375
0.0767
0.0524
9.0225
0.0037
9.0187
0.0112
0.4437
0.0019
0.0019
4.0412
9.0012
4.0012
4.4419
4.0419
4.4012
0.0012
0.4412
0.4473
0.0073
4.9475
0.0037
0.0037
4.4437
1.0000
0.8557
1.1444
1.0000
2.0000
3.0040
1.0000
4.0000
9.0000
3.9000
3.0000
5.0000
6.9444
1.9000
2.0400
2.0004
9.0404
13.0004
8.0000
5.0400
2.0000
1.0400
1.0400
3.0000
3.0009
5.0400
50.0000
12.0444
7.0000
8.0494
7.0000
12.0440
10.0000
21.0004
14.0400
6.4404
1.9000
5.0000
3.0009
1.0400
0.5400
4.3400
0.3333
0.3333
9.3333
9.5000
9.5944
0.3333
0.3333
0.3333
2.0400
2.0004
2.0040
1.0004
1.0404
1.4044
267.4444
247.0000
A-7
-------
TABLE A.4.
FACILITY SIZE
IKB/D SULFUR)
O.II-I.O
1.1-2.0
2.1-3.0
3.1-4.0
4.1-5.0
5.1-10.0
10.1-20.0
20.1-JO.O
30.1-40.0
40.1-50.0
50.1-60.0
40.1-70.0
70.1-80.0
80.1-90.0
90.1-100.0
100. -110.0
110. -120.0
120. -130.0
130. -140.0
MO. -150.0
150. -140.0
160. -170.0
170. -1BO.O
ISO. -190.0
190. -200.0
200. -300.0
300. -500.0
500. -750.0
750.1-1000.0
M004.1
v «'-::.:?« VITHU A EIVEX SUE met HAVIMS A IMS IN THE
KID 6AS KITH!* Txt HECIFIED RAHSES AND A DCS IN THE
SOUR SAS OF 0.01 TO 0.1 PESCEHT IH2S IK THE ACID SAS
0.00001
0.0000
0.0000
0.0000
0.0000
0.0000
0.0000
0.0000
0.0000
0.0000
0.0000
0.0000
0.0000
0.0000
0.0000
0.0000
0.0000
0.0000
0.0000
0.0000
0.0000
0.0000
0.0000
0.0000
0.0000
0.4000
0.0000
0.0000
0.0000
0.0000
0.0000
>0. 00001
< 0.0001
1 0.0043
JO. 0003
0.0001
0.0400
0.0000
0.0000
0.0000
0.0000
0.0000
0.0000
0.0000
0.0000
0.0000
0.0000
0.0000
0.0000
0.0000
0.0000
0.0000
0.0000
0.0000
0.0000
0.0000
0.0000
0.0000
0.0000
0.0000
0.0000
0.0000
0.0000
>0.0001
<0.001
0.0893
0.0131
\ 0.0033,
0.0000
0.0000
0.0000
0.0000
0.0000
0.0000
0.0000
0.0000
0.0000
0.0000
0.0000
0.0000
0.0000
0.0000
0.0000
0.0000
0.0000
0.0000
0.0000
0.0000
0.0000
0.0000
0.0000
0.0000
0.0000
0.0009
0.0000
>O.OOI
(0.01
0.0850
0.0299
0.0794
0.0242
0.0315
0.0150
0.0044
0.0000
0.0000
0.0000
0.0000
0.0000
0.0000
0.0000
0.0000
0.0000
0.0000
0.0000
0.0000
0.0000
0.0000
0.0000
0.0000
0.0000
0.0000
0.0000
0.0000
0.0000
0.0000
0.0000
>0.01
<0.02
0.0850
0.0349
0.0281
0.0049
0.0090
0.0111
0.0007
0.0000
0.0000
0.0000
0.0000
0.0000
0.0000
0.0000
0.0000
0.0000
0.0000
0.0000
0.0000
0.0000
0.0000
0.0000
0.0000
0.0000
0.0400
0.0000
0.0000
0.0000
0.0000
0.0000
>0.02
<0.05
0.0720
0.1454
0.0178
0.0027
0.0034
0.0031
0.0003
0.0000
0.0000 .
0.0000
0.0000
0.0000
0.0000
0.0000
0.4000
0.0000
4.4400
0.0000
4.0004
0.0040
4.0040
0.0000
0.0000
0.4000
0.0040
0.0000
0.4000
0.4440
0.4404
0.0004
>0.05
(0.125
0.0405
0.4472
0.0774
0.0258
0.0281
4.4199
0.0035
0.0000
0.0400
4.0004
0.0000
0.0000
4.0000
0.0000
4.0400
0.0000
0.0400
0.0004
4.0400
0.0040
0.0400
4.0044
0.0004
4.4400
0.4444
4.0000
4.0444
0.0000
4.0400
0.0000
XM25
<0.20
0.0430
0.0233
0.0444
4.1145
0.0149
4.0213
0.0139
0.0000
0.0040
0.0004
0.0000
0.0000
0.0000
0.0040
0.4409
4.4440
0.4444
4.4400
4.4040
0.0000
4.4040
0.0004
4.0000
0.0004
4.0000
0.0090
0.0000
0.4000
0.0004
0.9040
)4.29
<4.5
4.4224
0.0513
0.0755
0.0204
0.0407
0.0443
0.0301
0.0000
4.0400
0.0400
0.0000
0.0000
0.0400
0.0000
0.0000
4.4040
0.4009
9.0444
0.0444
0.4000
0.0400
0.0000
0.0004
9.4000
0.0000
4.4449
9.0004
0.0404
9.9000
9.0004
>0.5
(0.8
0.0101
0.0180
0.0322
*.0132
0.0257
0.0335
9.0171
9.9009
0.0040
4.9000
4.0040
4.4000
0.0009
0.4440
0.0000
0.0000
4.4449
0.0009
0.0090
0.0909
0.9000
0.0909
0.9009
9.9999
9.0009
9.0000
0.0099
0.0000
0.0099
9.9400
4.
4.
0.
0.
0.
0.
4.
0.
0.
0.
0.
0.
0.
0.
0.
9.
9.
9.
4.
4.
4.
4.
0.
0.
0.
0.
0.
0.
0.
0.
>o;a
(1.0
44!8
0041
0111
0023
0047
4087
4034
9009
0400
0099
0000
9099
0000
0099
0099
9009
0049
9099
9009
0990
9499
0900
0090
0000
0900
0090
0004
4999
0400
4004
A-8
-------
TABLE A.5.
FACILITY SIZE
(K6/D SULFUR)
O.U-1.0
1.1-2.0
2.1-3.0
3.1-1.0
4.1-5.0
!.i-:o.o
10.1-20.0
20.1-30.0
30.1-40.0
40.1-50.0
50.1-40.0
60.1-70.0
70.1-30.0
90.1-90.0
90. 1-100.0
100.1-110.0
110. -120.0
120. -130.0
130. -MO.O
140. -150.0
ISO. -liO.O
160. -170.0
170. -180.0
190. -190.0
190. -200.0
200. -300.0
3*1.1-500.0
MO. 1-750.0
750.1-1000.0
MOOO.l
MDJASILITY OF * FACILITY IITH1K A 6IVU SUE WWE HAVINS A IH2S III THE
KID SAS DITHIN THE SPECIFIED RAHSES A« A 1H2S IN THE
SOUR SAS OF 0.1 TO 1.0 PERCENT 1H2S IN THE ACID GAS.
>
9.04041
0.0000
0.0000
0.0000
0.0000
0.0000
0.0000
0.0000
0.0000
0.0000
0.0000
0.0000
0.0000
0.0000
0.0000
0.0000
0.0000
0.0000
0.0000
0.0000
0.0000
0.0000
0.0000
0.0000
0.0000
0.0000
0.0000
0.0000
0.0000
0.0000
0.0000
4.00041
.05
(4.125
4.4403
0.0804
0.1082
0.0754
0.4952
0.0655
0.0220
4.Q407
0.4004
0.0400
4.0404
4.4000
0.4444
0.0044
0.0004
4.0004
4.4044
0.0000
0.0444
0.0000
4.0400
0.4000
0.0044
0.4040
0.0000
0.0000
0.0004
0.0000
4.0000
0.0444
W.125
(0.20
0.0320
0.0284
4.0655
4.3325
4.0506
0.0700
0.0876
0.0577
4.0221
0.0275
0.0116
« 0049
0.0000
0.0000
0.4000
4.0000
0.0000
0.0000
4.0400
0.0000
0.0004
0.0000
4.0404
0.0040
0.0040
0.0000
4.4440
0.0040
4.0000
4.0000
>0.20
<4.5
0.0150
0.0613
0.1061
0.0558
0.2456
0.2117
0.1992
0.1558
0.1694
4.1484
0.1146
O.Oili
0.0400
0.0000
0.4000
0.0000
0.0040
0.0004
0.0444
0.0004
0.4000
4.4000
0.0000
0.0000
0.0040
4.0400
0.0404
4.0404
0.4004
0.0000
0.
0.
0.
0.
0.
0.
0.
0.
4.
0.
0
— fl.
0.
0.
0.
0.
0.
0.
0.
0.
0.
0.
4.
0.
0.
0.
0.
0.
4.
4.
M.5
(0.8
0067
0216
4452
0384
0872
1103
1074
0662
0333
0525
0610
0|«7
0000
0000
4404
0004
0440
0000
0040
0009
0000
0000
0000
0000
0000
0000
0000
0400
0000
0000
>o.s
-------
TABLE
. FACILITY SHE
IKS/0 SUUUK)
0.11-1.0
1.1-2.0
M-3.0
J.M.O
4.1-5.0
5.1-10.0
10.1-20.0
20.1-30.0
JO.1-40.0
40.1-50.0
50.1-60.0
40.1-70.0
70.1-80.0
80.1-90.0
90.1-100.0
100. -110.0
110. -120.0
120. -130.0
130. -140.0
140. -150.0
OF A FA::..-: VITHIN A sim SUE mx HAVINS A IH:S it THE
AtiD SAS IITH;N THS sn:'.?'.cj> RAXHS AM A ins in THE
SOUS MS OF 1.0 TO 2.0 ttKttT ZH2S IN THE ACID GAS
9.00001
0.0000
0.0000
0.0000
0.0000
0.0000
o.oooo
0.0000
0.0000
0.0000
0.0000
0.0000
0.0000
0.0000
0.0000
0.0000
0.0000
0.0000
0.0000
0.0000
0.0000
>0. 00001
(0.0001
0.0000
.0000
.0000
0.0000
0.0000
0.0000
0.0000
0.0000
0.0000
0.0000
0.0000
0.0600
0.0000
0.0000
0.0000
o.owo
0.0000
0.0000
0.0000
0.0000
M.0001
<0.001
0.0000
T.6022
0.0010
0.0000
o.oooo/
0.0000
o.ooooj
0.0000
0.0000
0.0000
0.0000
0.0000
0.0000
0.0000
0.0000
0.0000
0.0000
0.0000
0.0000
0.0000
>O.OOI
<0.01
0.0000
J.ooSi
0.0233
/ 0.0150
0.0228
0.0158
0.0020
0.0000
0.0000
0.0000
0.0000
0.0000
0.0000
0.0000
0.0000
0.0000
0.0000
0.0000
0.0000
0.0000
>0.01
(0.02
0.0000
~o:6«i
0.0084
0.0043
0.0065
0.0117
0.0023
0.0000
0.0000
0.0000
0.0000
0.0000
0.0000
0.0000
0.0000
0.0000
0.0000
0.0000
0.0000
0.0000
>0.02
<0.05
0.0000
•o.o.'sr
0.0053
0.0017
0.0025
0.0032
0.0024
0.0218
0.0000
0.0000
0.0000
0.0000
0.0000
0.0000
0.0000
0.0000
0.0000
0.0000
0.0000
0.0000
>0.05
(0.125
o.oooo
0.0115
0.0229
0.0140
0.0203
0.0211
0.0110
0.030SL
0.0000
0.0000
o.oooo
0.0000
0.0000
0.0000
0.0000
0.0000
0.0000
0.0000
0.0000
0.0000
>0.125
(0.20
0.0000
0.0041
0.0139
0.0709
0.0108
0.0225
0.0438
0.0437
0.04IB
0.0277
0.0174
0.0181
0.0012
0.0000
0.0000
0.0000
0.0000
0.0000
0.0000
0.0000
».20
<0.5
0.0000
0.0033
0.0224
0.0127
0.0438
0.0690
0.0946
0.1179
0.1485
0.1598
0.1719
0.22B3
0.0753
0.0000
0.0000
0.0000
0.0000
0.0000
0.0000
0.0000
)0.5
(0.8
0.0000
0.0031
0.0094
0.0082
0.0196
0.0355
0.0537
0.0501
0.0737
0.0547
0.0915
0.0/29
o.::?<
o.oooo
0.0000
0.0000
0.0000
0.0000
0.0000
0.0000
0.
0.
0.
0.
0.
>0.1i
(1.0
0000
oow
0033
0014
004S
0.4092
0.
.0.
0.
0.
0.
0.
0.
0.
0.
0.
0.
0.
0.
0.
0106
0157
0220
0238
0192
0107
0-33
0000
0000
0000
0000
0000
0000
0000
25
150.1-160.0
160.1-170.0
170.1-180.0
180.1-190.0 '
190.1-200.0
200.1-300.0
300.1-500.0
500.1-750.0
750.1-1000.0
>1000.1
0.0000
0.0000
0.0000
0.0000
0.0000
0.0000
0.0000
0.0000
0.0000
0.0000
0.0000
0.0000
0.0000
0.0000
0.0000
0.0000
0.0000
0.0000
0.0000
0.0000
0.0000
0.0000
0.0000
0.0000
0.0000
0.0000
0.0000
0.0000
0.0000
0.0000
0.0000
0.0000
0.0000
0.0000
0.0000
0.0000
0.0000
0.0000
0.0000
0.0000
o.oooo
0.0000
0.0000
0.0000
0.0000
0.0000
0.0(00
0.0000
0.0000
0.0000
0.0000
0.0000
0.0000
0.0000
0.0000
0.0000
0.0000
0.0000
0.0000
0.0000
0.0000
0.0000
0.0000
0.0000
0.0000
0.0000
0.0000
0.0000
0.0000
0.0000
0.0000
0.0000
0.0000
0.0000
0.0000
0.0000
0.0000
0.0000
0.0000
0.0000
0.0000
0.0000
0.0000
0.0000
0.0000
0.0000
0.0000
0.0000
0.0000
0.0000
0.0000
0.0000
0.0000
0.0000
0.0000
0.0000
o.oooc
0.0000
0.0000
0.0000
0.0000
0.0000
0.0000
0.0000
0.0000
0,0000
0.0000
0.0000
0.0000
0.0000
A-10
-------
TABLE A. 7.
F«um SIZE
IKS/D SULFUR!
0.11-1.0
1.1-2.0
2.1-3.0
3.1-4.0
4.1-5.0
5.1-10.0
10.1-20.0
20.1-30.0
30.1-40.0
40.1-50.0
50.1-60.0
60.1-70.0
70.1-90.0
BO.1-90.0
90.1-100.0
100.1-110.0
110.1-120.0
120.1-130.0
130.1-140.0
140.1-150.0
150.1-140.0
160.1-170.0
170.1-180.0
180.1-190.0
190.1-200.0
200.1-300.0
100.1-500.0
500.1-750.0
750.1-1000.0
MOOO.l
PROBABILITY OF A FACILITY HI THIN A GIVEN SHE UOBt HAV1N6 A 2H2S IN THE
ACID MS HIIHIN THEJPECIFIEJ RWiEES AM A IH25 I* THE
SOUS 6AS OF 2.0 TO jS PERCENT IMS IN THE ACID BAS_
1.00001
0.0000
0.0000
0.0000
0.0000
0.0000
0.0000
0.0000
0.0000
0.0000
0.0000
0.0000
0.0000
0.0000
0.0000
0.0000
0.0000
0.0000
0.0000
0.0000
0.0000
0.0000
0.0000
0.0000
0.0000
0.0000
0.0000
0.0000
o.oooo
0.0000
o.oooo
X). 00001
<0.0001
0.0000
.0000
.0000
0.0000
0.0000
0.0000
0.0000
0.0000
0.0000
0.0000
0.0000
0.0000
0.0000
0.0000
0.0000
0.0000
0.0000
0.0000
0.0000
0.0000
0.0000
0.0000
0.0000
0.0000
0.0000
0.0000
0.0000
0.0000
0.0000
0.0000
XI. 000!
(0.001
0.0000
O.OOij
J^OOM
o.ooocT
0.0000
0.0000
0.0000
0.0000
0.0000
0.0000
0.0000
0.0000
0.0000
0.0000
0.0000
0.0000
0.0000
0.0000
0.0000
0.0000
0.0000
0.0000
0.0000
0.0000
0.0000
0.0000
0.0000
o.oooo
0.0000
0.0000
xTooT
<0.01
0.0000
0.0029
0.014B
; 0.0058
0.0140
0.0062
0.0020
0.0000
0.0090
0.0000
0.0000
0.0000
0.0000
0.0000
0.0000
0.0000
0.0000
0.0000
0.0000
0.0000
0.0000
0.0000
0.0000
0.0000
0.0000
0.0000
0.0000
0.0000
0.0000
0.0000
W.OI
<0.02
0.0000
0.0036
0.0053
0.0017
0.0040
0.0044
0.0022
0.0000
0.0000
0.0000
0.0000
0.0000
0.0000
0.0000
0.0000
0.0000
0.0000
0.0000
0.0000
0.0000
0.0000
0.0000
0.0000
0.0000
0.0000
0.0000
0.0000
O.MOO
0.0000
0.0000
H.02
(0.03
0.0000
0.0162
0.0034
0.0007
0.0015
0.0013
0.0024
0.0203
'0.0000
0.0000
0.0000
0.0000
0.0000
0.0000
0.0000
0.0000
0.0000
0.0000
0.0000
0.0000
0.0000
0.0000
4.0000
0.0000
0.0000
0.0000
0.0000
0.0000
0.0000
0.0000
>0.05
(0.125
0.0000
0.0066
0.0144
0.0062
0.0125
0.0062
0.0110
0.0264_
0.0000
0.0000
0.0000
0.0000
0.0000
0.0000
0.0000
0.0000
0.0000
0.0000
0.0000
0.0000
0.0000
0.0000
0.0000
0.0000
0.0000
0.0000
0.0000
0.0000
0.0000
0.0000
xj.m
(0.20
0.0000
0.0023
0.0088
0.0273
0.0066
0.0066
0.04.3
0.0406
0.0411
0.0352
0.0162
0.0137
0.0017
0.0005
0.0000
0.0000
0.0000
0.0000
0.0000
0.0000
o.oooo
0.0000
o.oooo
0.0000
0.0000
0.0000
0.0000
0.0000
0.0000
0.0000
>0.20
(0.50
0.0000
0.0050
0.0143
0.0049
0.0270
0.02*5
0.0946
0.1095
0.1331
0.1894
0.1604
0.1729
0.1043
0.2524
0.1128
0.2309
0.1645
0.0960
0.1404
0.0690
0.0231
"0.6656 ~
0.0000
0.0000
0.0000
0.0000
0.0000
0.0000
0.0000
0.0000
>0.56
(0.80
0.0000
0.0015
0.0061
0.0032
O.OH4
0.0136
0.0537
0.0465
0.0660
0.0672
0.0854
0.0552
0.1779
0.1612
0.0960
0.1860
0.1400
0.1376
0.1692
0.0736
0.0539
0.0000
0.0900
0.0000
0.0000
0.0000
0.0000
0.0000
0.0000
0.0000
>O.So
;i.oo
0.0000 ^
0.0004
0.0021
0.0006
0.0030
0.0036
0.0106
0.'0146
0.0198
0.0282
0.0179
0.0384
0.0465
0.0559
O.OJ12
0.0411
0.0455
0.0864
0.0504
0.0874
o.ora_
0.0000
0.0000
0.0000
0.0000
0.0000
0.0000
0.0000
0.0000
0.0000
A-ll
-------
TABLE A.8.
FACILITY SIZE
(HB/0 SULFUR)
0.11-1.0
1.1-2.0
2.1-3.0
3.1-4.0
4.1-5.0
5.1-10.0
10,1-20.0
20.1-30.0
30.1-40.0
40.1-50.0
50.1-40.0
60.1-70.0
70.1-so.o
SO.1-90.0
M. 1-100.0
100.1-110.0
110.1-120.0
120.1-130.0
130.1-140.0
140.1-150.0
150.1-140.0
140.1-170.0
170.1-180.0
ISO.1-190.0
110.1-200.0
200.1-300.0
300.1-500.0
500.1-730.0
750.1-1000.0
MOOO.l
W83ABR1TY OF A FACILITY KITHIX A 6IVEK SIZE RAKE MVIXS A IH2S III THE
ACID SAS KITH1K THE SPECIFIED RANGES ADD A ZH2S III THE
SOUR SAS OF 5.0 TO 12.5 mti»l__ UCS IN THE ACJ8 6AS
3.00001
0.0000
0.0000
0.0000
0.0000
0.0000
0.0000
0.0000
0.0000
0.0000
0.0000
0.0000
o.oooo
0.0000
0.0000
0.0000
0.0000
0.0000
0.0000
0.0000
0.0000
0.0000
0.0000
0.0000
0.0000
0.0000
0.0000
0.0000
0.0000
0.0000
0.0000
M. 00001
(0.0001
0.0000
0.0000
0.0000
0.0000
0.0000
0.0000
0.0000
0.0000
0.0000
0.0000
0.0000
0.0000
0.0000
o.oooo
0.0000
0.0000
0.0000
0.0000
0.0000
0.0000
0.0000
0.0000
0.0000
0.0000
0.0000
0.0000
0.0000
0.0000
0.0009
0.0000
M.0001
<0.001
0.0000
0.0000
0.0000
0.0000
0.0000
0.0000
0.0000
0.0000
0.0000
o.oooo
0.0000
o.oooo
0.0000
0.0000
0.0000
0.0000
0.0000
0.0000
0.0000
0.0000
0.0000
0.0000
0.0000
0.0000
0.0000
0.0000
0.0000
0.0000
0.0000
0.0000
>0.001
(0.01
0.0000
0.0000
0.0000
0.0000
0.0000
;o.66l8
' O.OOOi^
0.0000
0.0000
0.0000
0.0000
0.0000
0.0000
0.0000
0.0000
0.0000
0.0000
0.0000
0.0000
0.0000
0.0000
0.0000
0.0000
0.0000
0.0000
0.0000
0.0000
0.0000
0.0000
0.0000
>O.OI
<0.02
0.0000
0.0000
0.0000
0.0000
0.0000
• IT. Mir
0.0004
0.0000
0.0000
0.0000
0.0000
0.0000
0.0000
0.0000
0.0000
0.0000
0.0000
0.0000
0.0000
0.0000
0.0000
0.0000
o.oooo
0.0000
0.0000
0.0000
0.0000
0.0000
0.0000
0.0000
X.02
(0.05
0.0000
0.0000
0.0000
0.0000
0.0000
"ORFT
0.0004
|_O.OOS2
0.0000
0.0000
0.0000
0.0000
0.0000
0.0000
o.oooo
0.0000
0.0000
0.0000
o.oooo
0.0000
0.0000
0.0000
0.0000
0.0000
0.0000
0.0000
0.0000
0.0000
0.0000
0.0000
X3.05
(0.125
0.0000
0.0000
0.0000
0.0000
0.0000
U«3
0.0020
0.0083
0.0000
0.0000
0.0000
0.0000
0.0000
0.0000
0.0000
0.0000
0.0000
0.0000
0.0000
0.0000
0.0000
0.0000
0.0000
o.oooo
0.0000
0.0000
0.0000
0.0000
0.0000
0.0000
>0.12S
(0.20
0.0000
0.0000
0.0000
0.0000
0.0000
0.0025
0.0080
0.0125
0.0158
0.0154
0.0110
0.0098
0.0019
0.0004
O.OOOu
0.0000
0.0000
0.0000
0.0000
0.0000
0.0000
0.0000
0.0000
0.0000
0.0000
0.0000
0.0000
0.0000
0.0000
0.0000
>0.2fl
(0.5
0.0000
0.0000
0.0000
0.0000
0.0000
0.0074
0.0172
0.0337
0.0512
0.0829
0.1089
0.1234
0.1201
0.2343
0.1314
0.2254
0.2142
0.1450
0.2028
0.1890
0. 1407
0.172S
0.0840
0.0525
0.0420
lJ.0000
0.0000
o.oooo
0.0000
0.0000
X>.5
o.a
(1.0
0.0000
0.0000
0.0000 .
0.0000
O.MOO
0.0010
0.0019
0.304!
O.>)074
0.0123
0.0122
0.0274
0.0534
0.0524
0.0344
0.0*24
0.0598
O.M85
0.0728
0.2394
0.2010
0.2175
0.1980
0.24.Z5
0.3000
JJ&2 .
0.0000
o.ooco
o.ooco
0.0000
A-12
-------
TABLE A.9.
FACILITY SIZE
(KS/D SULKS)
0.11-1.0
1.1-2.0
2.1-3.0
3.1-4.0
4.1-5.0
5.1-10.0
10.1-20.0
20.1-30.0
30.1-40.0
40.1-50.0
50.1-40.0
W. 1-70.0
70.1-80.0
BO.1-90.0
90.1-100.0
100. -110.0
110. -120.0
120. -130.0
130. -140.0
140. -150.0
ISO. -160.0
160. -170.0
170. -180.0
180. -190.0
190. -200.0
200. -300.0
300. -500.0
500. -750.0
750. -1000.0
MOOO.l
PROBABILITY OF A FACILITY VITKIX A S!V£N SIZE SAME HAVIK A IH2S III Tie
AdB MS KITHU TK SPttlFIEJ RMEES AW A IMS 11 THE
SOUR CAS OF 12.S TO 20.0 PERCEHT IH2S IN THE ACID SAS.
1.00001
0.0000
0.0000
0.0000
0.0000
0.0000
0.0000
0.0000
0.0000
0.0000
0.0000
0.0000
0.0000
0.0000
0.0000
0.0000
0.0000
0.0000
0.0000
0.0000
0.0000
0.0000
0.0000
0.0000
0.0000
0.0000
0.0000
0.0000
0.0000
0.0000
0.0000
>0.00001
(0.0001
4.0000
0.0000
0.0000
0.0000
0.0000
0.0000
0.0000
0.0000
0.0000
0.0000
0.0000
0.0000
0.0000
0.0000
0.0000
0.0000
0.0000
0.0000
0.0000
0.0000
0.0000
0.0000
0.0000
.0000
.0000
.0000
.0000
.0000
.0000
0.0000
M.OOO!
(0.001
0.0000
0.0000
0.0000
0.0000
0.0000
0.0000
0.0000
o.oooc
0.0000
0.0000
0.0000
0.0000
0.0000
0.0000
0.0000
0.0000
0.0000
0.0000
0.0000
0.0000
0.0000
.0.0000
0.0000
0.0000
0.0000
0.0000
0.0000
0.0000
0.0000
0.0000
XJ.001
(0.01
0.0000
0.0000
0.0000
0.0000
0.0000
0.0000
0.0000
0.0000
0.0000
0.0000
0.0000
0.0000
0.0000
0.0000
0.0000
0.0000
0.0000
0.0000
0.0000
0.0000
0.0000
0.0000
0.0000
0.0000
0.0000
0.0000
0.0000
0.0000
0.0000
0.0000
XI.01
(0.02
0.0000
0.0000
0.0000
0.0000
0.0000
0.0000
0.0000
0.0000
0.0000
0.0000
0.0000
0.0000
0.0000
0.0000
0.0000
0.0000
0.0000
0.0000
0.0000
0.0000
0.0000
o.oow
0.0000
0.0000
0.0000
0.0000
0.0000
0.0000
0.0000
0.0000
W.02
(0.05
0.0000
0.0000
0.0000
0.0000
0.0000
0.0000
0.0000
J.'JOIS
0.0000
0.0000
0.0000
0.0000
0.0000
0.0000
0.0000
0.0000
0.0000
0.0000
0.0000
0.0000
0.0000
0.0000
0.0000
0.0000
0.0000
0.0000
0.0000
0.0000
0.0000
0.0000
>0.05
(0.123
0.0000
0.0000
0.0000
0.0000
0.0000
0.0000
0. 0000
o.oo::
0.0000
0.0000
0.0000
0.0000
0.0000
O.OOOv
0.0000
0.0000
0.0000
0.0000
0.0000
0.0000
0.0000
0.0000
0.0000
0.0000
0.0000
0.0000
0.0000
0.0000
0.0000
0.0000
XJ.123
(0.20
0.0000
0.0000
0.0000
0.0000
0.0000
0.0000
0.0000
0.0031
0.0032
0.0022
0.0023
0.0020
0.0002
0.0001
1 0.0000
0.0000
0.0000
0.0000
0.0000
0.0000
0.0000
0.0000
0.0000
0.0000
0.0000
0.0000
0.0000
0.0000
0.0000
0.0000
)
0.
0.
0.
0.
0.
0.
9l
0.
0.
0.
0.
0.
0.
0.
0.
0.
0.
0.
0.
0.
0.
0.
0.
0.
J.
0.
0.
0.
0.
0.
0.20
(0.3
0000
0000
0000
0000
0000
0000
0000
0064
0102
0118
0229
0247
0126
0483
2236
0185
0893
0360
0463
0420
0462
0575
0560
0173
0230
oowT
0000
0000
0000
0000
>0.5
(0.8
0.0000
0.0000
0.0000
0.0000
0.0000
0.0000
0.0000
0.0036
0.0031
0.0042
0.0122
0.0079
0.0216
0.0309
0.1920
0.0160
0.0760
0.0516
0.0364
0.0443
0.1078
0.1200
0.2120
0.1(50
0.1720
kO.J)!0°
o.oooo I
0.0000
0.0000
>0.8
(1.0
0.0000
0.0000
0.0000
0.0000
0.0000
0.0000
0.0000
0.0011
0.0015
0.0018
0.0026
0.0035
0.0056
0.0107
0.0«(
0.0032
0.0247
0.0324
o.oua
0.0532
0.0660
0.0723
0.1320
0.0973
0.2000
0.0792
1.0000
_0.50_00
0.0000
0.0000
A-13
-------
TABLE A.10
FACILITY SIZE
(Kfi/D SULFUR)
0.11-1.0
1.1-2.0
2.1-3.0
3.1-4.0
4.1-3.0
5.1-10.0
10.1-20.0
20.1-30.0
30.1-40.0
40.1-50.0
50.1-60.0
M. 1-70.0
70.1-80.0
80.1-90.0
90.1-100.0
100.1-110.0
110.1-120.0
120.1-130.0
130. -140.0
140. -1SO.O
130. -UO.O
140. -170.0
170. -190.0
1BO. -190.0
190. -200.0
200. -300.0
300. -500.0
500. -750.0
750. -1000.0
>I000.1
PROBABILITY OF A FACILITY VITHM A 6IVEK SIZE M«£ HAVING A IK2S III THE
ACID SAS IITHIN THE SPECIFIC RMSES AHD A IH2S U THE •
SOUR SAS OF 20.0 TO 50.0 PERCENT DCS III THE ACID 6AS
1.00001
0.0000
0.0000
0.0000
0.0000
0.0000
0.0000
0.0000
0.0000
o.oooo
0.0000
0.0000
0.0000
0.0000
0.0000
0.0000
0.0000
0.0000
0.0000
0.0000
0.0000
0.0000
0.0000
o.oooo
0.0000
0.0000
0.0000
0.0000
0.0000
0.0000
0.0000
M. 00001
<0.0001
0.0000
0.0000
0.0000
0.0000
0.0000
0.0000
0.0000
0.0000
0.0000
0.0000
0.0000
0.0000
0.0000
0.0000
0.0000
0.0000
0.0000
0.0000
0.0000
0.0000
0.0000
0.0000
0.0000
0.0000
0.0000
0.0000
0.0000
0.0000
0.0000
0.0000
M.0001
(0.001
0.0000
o.oooo
0.0000
0.0000
0.0000
0.0000
0.0000
0.0000
0.0000
0.0000
0.0000
0.0000
0.0000
0.0000
0.0000
0.0000
0.0000
0.0000
0.0090
0.0000
0.0000
0.0000
0,0000
0.0000
0.0000
0.0000
0.0000
0.0000
o.oooo
0.0000
>0.001
<0.01
0.0000
0.0000
0.0000
0.0000
0.0000
0.0000
0.0000
0.0000
0.0000
0.0000
0.0000
0.0000
0.0000
0.0000
0.0000
0.0000
0.0000
0.0000
0.0000
0.0000
0.0000
0.0000
0.0000
0.0000
0.0000
0.0000
0.0000
0.0000
0.0000
0.0000
>0.01
<0.02
0.0000
0.0000
0.0000
0.0000
0.0000
0.0000
0.0000
0.0000
0.0000
0.0000
0.0000
0.0000
0.0000
0.0000
0.0000
0.0000
0.0000
0.0000
0.0000
0.0000
0.0000
0.0000
0.0000
0.0000
0.0000
0.0000
0.0000
0.0000
o.oooo
0.0000
>0.02
.3
-------
TABLE A.11. BASELINE COSTS
($1000-1984)
FACILITY
SIZE
(LT/D)
2
2
2
2
2
2
2
2
2
2
2
2
2
2
2
2
2
3
3
3
3
3
3
3
3
3
4
4
4
4
4
b
5
5
5
5
5
6
6
6
6
6
6
6
6
ACID
GAS
%H?S
2
5
5
5
12.5
12.5
12.5
12.5
12.5
20
20
20
20
20
50
50
80
2
5
5
12.5
12.5
12.5
20
20
50
5
5
12.5
12.5
20
2
5
5
12.5
12.5
20
2
5
12.5
12.5
12.5
12.5
20
20
SOUR
GAS
%H?S
1
3
2
1
5
4
3
2
1
5
4
3
2
1
5
4
5
1
3
2
5
4
3
b
4
5
3
2
5
4
5
1
3
2
5
4
5
1
3
8
7
6
5
11
10
I/
CAPITAL
COST
2827
1986
1986
2015
1652
1661
1661
1661
1690
1580
1580
1580
1580
1609
1499
1499
1479
3504
2257
2257
1770
1770
1770
1648
1648
1526
2527
2556
1878
1878
1716
4887
2798
2827
1986
1986
1783
5563
3098
2094
2094
2094
2094
1851
1851
2/ 3/
ANNUAL SULFUR
O&M CREDIT
288
207
207
216
170
178
178
178
187
171
171
171
171
180
164
164
162
34y
231
231
188
188
188
177
177
166
255
264
198
198
183
489
279
288
207
207
189
549
313
217
217
217
217
195
195
NET
ANNUAL
O&M
288
207
207
216
170
178
178
178
187
171
171
171
171
180
164
164
162
349
231
231
188
188
188
177
177
166
255
264
198
198
183
489
279
288
207
207
189
549
313
217
217
217
217
195
195
4/
WORKING
CAPITAL
565
397
397
403
330
332
332
332
338
316
316
316
316
322
300
300
296
701
451
451
354
354
354
330
330
305
505
511
376
376
343
977
560
565
397
397
357
1113
620
419
419
419
419
370
370
5/
SALVAGE
VALUE
1131
794
794
806
661
664
664
664
676
632
632
632
632
644
600
600
592
1402
903
903
708
708
708
659
659
610
1011
1022
751
751
686
1955
1119
1131
794
794
713
2225
1239
838
838
838
838
740
740
A-15
-------
TABLE A.11. (Continued)
FACILITY
SIZE
(LT/D)
6
6
6
6
6
6
6
6
7
7
7
7
7
7
7
7
7
7
7
7
7
7
7
7
7
7
10
10
10
10
10
10
10
10
10
10
10
10
20
20
20
20
30
30
30
30
ACID
GAS
%H?S
20
20
20
20
50
50
50
80
2
5
5
12.5
12.5
12.5
12.5
20
20
20
20
20
20
50
50
50
80
80
2
5
5
12.5
12.5
20
20
20
50
50
80
80
12.5
20
50
80
12.5
12.5
20
20
SOUR
GAS
%H?S
9
8
7
6
12
11
10
12
1
3
2
8
7
6
5
12
11
10
9
8
7
12
11
10
12
11
1
3
2
6
5
. 9
8
7
12
11
12
11
7
11
12
12
8
7
13
12
I/
CAPITAL
COST
1851
1851
1851
1851
1607
1607
1607
1546
6240
3368
3368
2203
2203
2203
2203
1919
1919
1919
1919
1919
1919
1634
1634
1634
1563
1563
11277
6581
6611
4980
5009
4433
4433
4433
3537
3537
2890
2890
7323
6119
4653
3742
9321
9321
7450
7450
2/
ANNUAL
O&M
195
195
195
195
173
173
173
168
610
337
337
226
226
226
226
201
201
201
201
201
201
176
176
176
170
170
1741
1281
1301
1057
1066
924
924
924
756
756
707
707
1286
1031
763
545
1471
1471
1080
1080
3/
SULFUR
CREDIT
156
171
171
184
184
185
185
185
188
188
191
191
376
380
384
389
563
563
569
569
NET
ANNUAL
O&M
195
195
195
195
173
173
173
168
610
337
337
226
226
226
226
201
201
201
201
201
201
176
176
176
170
170
1585
1110
1130
873
882
739
739
739
568
568
516
516
910
651
379
156
908
908
511
511
4/
WORKING
CAPITAL
370
370
370
370
321
321
321
309
1248
674
674
441
441
441
441
384
384
384
384
384
384
327
327
327
313
313
2255
1316
1322
996
1002
887
887
887
707
707
578
578
1465
1224
931
748
1864
1864
1490
1490
5/
SALVAGE
VALUE
740
740
740
740
643
643
643
618
2496
1347
1347
881
881
881
881
768
768
768
768
768
768
654
654
654
625
625
4511
2632
2644
1992
2004
1773
1773
1773
1415
1415
1156
1156
2929
2448
1861
1497
A-16
-------
TABLE A.11. (Continued)
FACILITY
SIZE
(LT/D)
30
30
30
40
40
40
40
40
50
50
50
50
50
75
75
75
100
ACID
GAS
%H?S
20
50
80
12.5
20
20
50
80
12.5
20
20
50
80
12.5
20
50
20
SOUR
GAS
%H?S
11
19
19
8
13
12
19
19
8
14
13
19
19
9
14
19
15
I/
CAPITAL
COST
7450
5277
3958
11306
8780
8780
5903
4244
13260
10111
10111
6511
4631
18255
13467
8268
18229
2/
ANNUAL
O&M
1080
733
487
1670
1118
1118
684
425
1872
1177
1177
647
349
2312
1320
537
1382
3/
SULFUR
CREDIT
569
577
583
752
758
758
769
111
939
948
948
961
971
1409
1422
1442
1896
NET
ANNUAL
O&M
511
156
-96
918
360
360
-85
-352
933
229
229
-314
-622
903
-102
-905
-514
4/ 5/
WORKING SALVAGE
CAPITAL VALUE
1490
1055
792
2261
1756
1756
1181
849
2652
2022
2022
1302
926
.3651
2693
1654
3646
_!/ For the derivation of these costs see Docket A-80-20-A.
27 Ibid.
3/ Assumes 75% capacity utilization.
57 Calculated at 20% of capital costs.
5/ Calculated at 40% of capital costs.
A-17
-------
TABLE A.12. REGULATORY ALTERNATIVE III COSTS
FACILITY
SIZE
(LT/D)
2
2
2
2
2
2
2
2
2
2
2
2
2
2
2
2
2
3
3
3
3
3 •
3
3
3
3
4
4
4
4
4
5
5
5
5
5
5
6
6
6
6
6
6
6
ACID
GAS
%H?S
2
5
5
5
12.5
12.5
12.5
12.5
12. b
20
20
20
20
20
51)
50
80
2
5
5
12.5
12.5
12.5
20
20
50
5
5
12.5
12.5
20
2
5
5
12.5
12.5
20
2
5
12.5
12.5
12.5
12.5
20
SOUR
GAS
%H?S
1
3
2
1
5
4
3
2
1
5
4
3
2
1
5
4
b
1
3
2
5
4
3
5
4
5
3
2
5
4
5
1
3
2
5
4
5
1
3
8
7
6
5
11
1
CAPITAL'
COST
3797
2717
2717
2746
2219
2228
2228
2228
2257
2147
2147
2147
2147
2176
2066
2066
2046
4812
3249
3249
2557
2557
2557
2435
2435
2313
3781
3810
2936
2936
2774
6871
4324
4353
3283
3283
3080
8081
4802
3427
3427
3427
3427
3184
($1000-1984)
7 2/ 3/
ANNUAL SULFUR
O&M CREDIT
911
733
733
742
655
663
663
663
672
656
656
656
656
665
649
649
647
1041
780
780
712
712
712
701
701
690
832
841
748
748
733
1278
880
889
799
799
781
1396
953
888
888
888
888
866
79
86
86
90
90
93
98
107
111
111
111
111
116
NET
ANNUAL
O&M
911
733
733
742
655
663
663
663
672
656
656
656
656
665
649
649
647
1041
780
780
712
712
712
701
701
690
832
841
748
748
733
1199
794
803
709
709
688
1298
846
111
111
111
111
750
4/ 5/
WORKING SALVAGE
CAPITAL VALUE
759
543
543
549
444
446
446
446
451
429
429
429
429
435
413
413
409
962
650
650
511
511
511
489
489
462
756
762
587
587
555
1374
865
871
' 657
657
616 •
1616
960
685
685
685
685
637
1519
1087
1087
1098
888
891
891
891
903
859
859
859
859
870
826
826
818
1925
1300
1300
1023
1023
1023
974
974
924
Ibl2
1524
1174
1174
1110
2748
1730
1741
1313
1313
1232
3232
1921
1371
1371
1371
1371
1274
A-18
-------
TABLE A.12. (Continued)
FACILITY
SIZE
(LT/0)
6
6
6
6
6
6
6
6
6
7
7
7
7
7
7
7
7
7
7
7
7
7
7
7
7
7
7
10
11)
10
10
10
10
10
10
10
10
10
10
20
20
20
20
30
30
ACID
GAS
%H?S
20
20
20
20
20
50
50
50
80
2
5
5
12.5
12.5
12.5
12.5
20
20
20
20
20
20
50
50
50
80
80
2
5
5
12.5
12.5
20
20
20
50
50
80
80
12.5
20
50
80
12.5
12.5
SOUR
GAS
%H?S
10
9
8
7
6
12
11
10
12
1
3
2
8
7
6
5
12
11
10
9
8
7
12
11
10
12
11
1
3
2
6
5
9
8
7
12
11
12
11
7
11
12
12
8
7
I/
CAPITAL
COST
3184
3184
3184
' 3184
3184
2940
2940
2940
2879
9052
5250
5250
3751
3751
3751
3751
3467
3467
3467
3467
3467
3467
3182
3182
3182
3111
3111
11964
7069
7099
4609
4638
4150
4150
4150
3940
3940
3838
3838
7291
5977
4064
3861
9277
9277
21
ANNUAL
O&M
866
866
866
866
866
844
844
844
839
1502
1049
1049
934
934
934
934
909
909
909
909
909
909
884
884
884
878
878
1812
1330
1350
1074
1083
957
957
957
885
885
876
876
1236
1288
707
669
1429
1429
3/
SULFUR
CREDIT
116
116
116
116
116
116
116
116
116
113
124
124
129
129
129
129
135
135
135
135
135
135
143
143
143
135
135
162
177
177
185
185
193
193
193
193
193
193
193
377
395
398
398
603
603
NET
ANNUAL
O&M
750
750
750
750
750
728
728
728
723
1389
925
925
805
805
805
805
774
774
774
774
774
774
741
741
741
743
743
1650
1153
1173
889
898
764
764
764
692
692
683
683
859
893
309
271
826
826
4/
WORKING
CAPITAL
637
637
637
637
637
588
b88
588
576
1810
1050
1050
750
750
750
750
693
693
693
693
693
693
636
636
636
622
622
2393
1414
1420
922
928
830
830
830
788
788
768
768
1458
1195
813
772
1855
1855
5/
SALVAGE
VALUE
1274
1274
1274
1274
1274
1176
1176
1176
1152
3621
2100'
2100
1500
1500
1500
1500
1387
1387
1387
1387
1387
1387
1273
1273
1273
1244
1244
4786
2828
2840
1844
1855
1660
1660
1660
1576
1576
1535
1535
2916
2390
1626
1544
A-19
-------
TABLE A.12. (Continued)
FACILITY
SIZE
(LT/D)
3D
30
30
30
30
40
40
40
40
40
50
50
50
50
50
75
75
75
100
ACID
GAS
%H2S
20
20
20
50
80
12.5
20
20
50
80
12.5
20
20
50
80
12.5
20
50
2U
SOUR
GAS
%H2S
13
12
11
19
19
8
13
12
19
19
8
14
13
19
19
9
14
19
15
I/
CAPITAL
COST
7919
7919
7919
5255
4950
11295
9685
9685
6393
5988
13282
11354
11354
7405
6398
18250
15244
9728
20158
2/
ANNUAL
O&M
1349
1349
1349
721
694
1643
1409
1409
755
719
1836
1468
1468
779
734
2321
1640
840
1754
3/
SULFUR
CREDITS
593
593
593
597
597
755
791
791
796
797
944
989
989
995
995
1416
1483
1492
1977
NET
ANNUAL
O&M
756
756
756
124
97
888
618
618
-41
-78
892
479
479
-216
-261
905
157
-652
-223
4/ 5/
WORKING SALVAGE
CAPITAL VALUE
1584
1584
1584
1051
990
2259
1937
1937
1279
1198
2656
2271
2271
1481
1280
3650
3049
1946
4032
I/ For the derivation of these costs see Docket A-80-20-A.
2/ Ibid.
3_/ Assumes 75% capacity utilization.
4_/ Calculated at 20% of capital costs.
5/ Calculated at 40% of capital costs.
A-20
-------
This estimate has been made by taking the inverse of the price/ earnings
ratio of 8.0 noted in Table 9-14, page 9-32, of the proposal BID. This
method is acceptable for making approximations of this rate because given a
specific stream of earnings, the price of a firm's security should adjust
until an acceptable return becomes available to potential investors.
In order to convert the nominal returns noted into real rates of
return, an assumption about current and future rates of inflation must be
made. For purposes of this analysis, an annual inflation rate of 5% is
used, based upon recent increases in the Consumer Price Index. Subtracting
this rate from the nominal rates of return noted above provides real
rates of return of 6.0 and 7.5% for interest and equity, respectively.
These rates appear realistic and reflect the greater risk inherent in
investments in the oil and gas industry.
In addition to the above, it has been assumed that debt incurred by the
plant will be repaid over a period equal to half the operating life of the
facility. Therefore, plants equal to or less than 20 LT/D would repay
loans over 6 years, while plants greater than 20 LT/D would repay loans
over 10 years.
Finally, it is assumed that royalty payments of 12.5% of gross revenues
are paid by the lessee to the lessor (i.e., owner).3 Due to the difficulties
inherent in calculating depletion exemptions, such as calculation of land
costs and costs of mineral rights, a depletion allowance has not been
included in this analysis. This amounts to is an overstatement of taxes
and is, therefore, a conservative assumption with regard to financial
viability.
A.5 Discounted Cash Flow Analysis
The discounted cash flow (DCF) analysis has five major steps:
1) Estimate the costs for the baseline and Regulatory Alternative
III, for each model plant (operating at 75% capacity) and each
acid gas percent.
2) Estimate the revenues for various combinations of model plant
size, acid gas percent, and sour gas percent assuming 75%
capacity utilization and 5% severance tax.
3) Eliminate from further consideration cases that are economically
A-21
-------
infeasible in the baseline. Elimination is based on a rough
approximation of net present value, made by examination of annuity
factors, and allows for the elimination of approximately 5% of all
situations presented in Table A.13. This reduces the number of
cases that need to be evaluated through the DCF computer model.
4) Estimate the net present value (i.e., economic feasiblity) of
remaining cases under both the baseline and Regulatory Alternative
III, and
5) Evaluate the economic impacts based upon the results of the net
present value (i.e., discounted cash flow) analysis, and sulfur
content probability tables.
For tnose cases that remain after the screening process described above,
the DCF model is used to distinguish three groups of facilities: 1) those
that are not economically feasible under the baseline, 2) those that are
economically feasible under the baseline but are not economically feasible
under Regulatory Alternative III, and 3) those that are economically feasible
under both the baseline and Regulatory Alternative III. The identification
of plants fitting the second of these groups is the primary purpose of this
analysis. Finally, in order to evaluate the potential for economic impacts
(i.e., postponement of new plant construction, supply restrictions, and
price increases) the probability tables are consulted to determine the
probability that new plants would display the acid and sour gas characteristics
of those plants falling into the second group noted above.
A.6 Discounted Cash Flow Analysis Results
By way of example, the analysis and results for the 2 LT/0, 5% acid
gas plant are presented in detail on the following tables. This size
category provides a good example because plants fitting each of the three
groups noted above can be observed. Plants that are 2 LT/D, 5» acid gas,
and either 5% or 4* sour gas were not run on the DCF model because the
screening analysis showed the baseline cases to be uneconomical. The
2 LT/0, b% acid gas, 3%-sour gas case, see Table A.14, was run and shown to
be economically feasible under the baseline situation. This can be observed
by noting that the net present value at the end of ID years was 2388.65
thousand. Under Regulatory Alternative III, see Table A.15, this situation
changed and the plant was no longer economically feasible. Note tne negative
A-22
-------
TABLE A.13.
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-------
TABLE A.14.
2LT/OAY. sz AC:D CAS. si SOUR SAS
DISCOUNTED CASH FLOW ANALYSIS FOB ALTERNATIVE 1
ANALYSIS IN CONSTANT DOLLARS (UNITS EXPRESSES AS THOUSANDS Of 1984 DOLLARS)
MEW FINAMCINOl PERCENT DEBT 13.98 INVeSTMgNTi EQUIPMENT 1956.80
PERCENT EoulTY sa.ee BUILDINGS .80
PERCENT CNT.08T. .ae LAND .88
PERCENT cNT.ca. .ae WORKING CAP. 387.ee
CNT.COUIP. .ae
TEAR 12343
REVENUES 423.ee 443.88 4*3.ea 494. ee 397.ea
out COSTS i79.aa 179.aa 179.88 i79.se tTv.ae
DEPRECIATION 387.29 59a. a: 4:1.44 267.sa 1:7.4=
INTEREST 69.69 S*.86 44.S4 32.71 II. 38
CONTROL COM COSTS .68 .00 .98 .88 . .00
EARNINGS BEFORE TAX -212.89 -382.38 -161.99 4.69 174.:a
DCPLETIOM ,aa .89 .93 .BO .88
TAX LOSS ,ea .88 .aa -4.69 -179.:a
TAX RATE .oeeee .eeeea .aeeae .aeeea .aeege
TAX LIABILITY .88 .98 .89 .aa .08
INVESTMENT TAX COT. .W .84 .80 .88 .99
ntNirun TAX .88 .ae . .88 .eg . ea
TOTAL TAX DUE .88 .88 .88 .88 .80
EARNINGS AFTER TAX -2i:.8<> -38:.38 -181.99 4.69 179.2O
DEPRECIATION 387.28 398.82 421.44 2*7.58 127.42
DEPLETION .88 .88 .88 .88 .ae
CASH FLOW BtF.oeOT. 174.31 2B7.14 2I».44 272.23 286.62
RES. PRINCIPAL 1*6.32 1*3.18 16*.78 171.3: 17:.95
SUS.CAP.EIP. • .«8 .80 .80 .88 .88
ITRA.CASH IH-n.OUS .88 .88 .80 . M .88
WORK. CAP. RECOVERY .88 .88 .88 .88 .88
NET CASH FLOW 7.79 39.84 t». 73 188.96 1=.67
DISCOUNT FACTOR .»3ai: .*6Sr3 .se<94 ,74aaa .69626
DSCT.MET CASH FLOM 7.23 3S.78 36.13 73.68 93.11
YEAR 6 7 8 9 18
RCVENUES sza.aa s:4.aa sea.aa 686.ea 634.aa
OW1 COST9 179.88 179.88 179.88 179.38 179.88
DEPRECIATION .88 .88 .88 .88 .08
INTEREST 18.48 .88 .88 .88 .88
CONTROL 0*J1 COSTS ,»8 .88 .88 • .88 .88
EJRNIN6S §E?0«E TAX 348.3: STS.ae 481.88 4:7.88 433.88
DEPLETION .88 .88 .88 .80 .88
TAX LOSS -348.32 -233.33 .88 .88 .80
TAI RATE .aeeea .3*3S7 . ;4S9S8 .46238 .46349
TAX LIABILITY .88 41.88 184.26 197.32 211.88
INVESTMENT TAX CDT. .88 39.29 188.18 .88 .89
BINImrt TAX .88 .88 •' .88 .80 .88
TOTAL TAI DOE .88 2i.S2 84.88 197.32 211.89
EARNINGS AFTER TAX 348.32 • 372.48 316.92 2=9.48 24J. 29
DEPRECIATION .88 .88 .88 .80 .88
DEPLETION .80 .88 .88 .88 .88
CASH FLOW BSF.DEOT. 348.32 372.48 316.92 229.48 243.29
RE9. PRINCIPAL 174.60 .88 .88 .88 .88
fUS.CAP.E3P. .88 .88 .88 .88 .88
XTRA.CASH IN-FLOHS .88 .88 .88 .80 .88
MORK.CAP.RECOVERY ' .88 .89 .88 .88 .98
NET CASH FLOW 163.4J 372.»« 116.9: 229.48 243.28
DISCOUNT FACTOR .64796 .6a276 .1*878 .S2I38 .48519
06CT.MTT CASH FLOH 187.31 224.31 177.79 119.69 118.88
YEAR 11 12
REVENUES 634.88 634.88
OU1 COSTS 179.98 179.8*
DCPKCCIATION .88 .88
INTEREST .80 .88
CONTROL OWt COSTS .88 .90
EARNINGS BEFORE TAX 433.88 4SS.88
DEPLETION . .80 .89
TAX LOSS .98 .89
TAX RATE .44349 .46349
TAX LIABILITY 211.88 211.80
INVESTnEMT TAX C3T. .88 .99
niNirun TAX .88 .ae
TOTAL TAI DUE 211.88 211.88
EARNtNOS AFTER TAX 243.73 243.M
DEPRECIATION .88 .88
DEPLETION .88 .88
CASH FLOW BEF.06DT. 243.28 243.28
Rea. PRINCIPAL .ae .ee
SUS.CAP.EXP. .88 .88
XTRA.CASH IN-FLOWS .80 387.90
HORK. CAP. RECOVERY .90 3S7.BO
NET CASH FLOW 243.29 1817.28
DISCOUNT FACTOR .43134 .41986
OSCT.NCr CASH FLOW 199.77 427.88
PRESENT VALUE Of CASH FLOWS FOR 12 TEARS IS 1358.IS
LESS EOUITV SHARE OF ORI8INAL INVESTMENT 1161.38
MET PRESENT VALUE IS 368.63
THE IRR IS 11.13 PERCENT
SINCE UCRCIMS CAPITAL IS RECOVERED IT IS
--- -- •• - - -
A-24
-------
TABLE A.15.
2UT/DAY. 3X ACID 8JS. IS SOUR GAS
DISCOUNTED CASH FLOU ANALYSIS FOR ALTERNATIVE tl!
ANALYSIS IN CONSTANT DOLLARS (UNITS EIPRESSE3 AS THOUSANDS 0" 1*84 DOLLARS)
NEU FINANCINGl PERCENT DEBT 39.M INVEBTT*NT| EQUIPMENT 2447.B8
PERCENT CQUITV sa.ee 8UIL0IN8S .DO
PERCENT CNT.08T. . 83 LANO .00
PERCENT CNT.EO. .80 NORKINO CAP. 833.88
CNT.COUIP. .88
Y6» I 2 J 4 S
REVENUES 42i.ee 443.ee 4*3.98 4«4.ee sar.ea
out COSTS Tes.ee 7es.ea 7es.ea 701.00 ros.oa
DEPRECIATION 333.48 812.88 568.57 348.4: I7S.S3
INTEREST **.88 78.32 *1.34 43.aa 7*.42
CONTROL otn COSTS .ea .ee .BO .ee .00
EARNINGS BEFORE TAX -*»i.4o -1133.12 -«83.T3 -*34.7a -4e:.*a
DEPLETION .ea .ee .ee .ea .ae
TAI LOSS .ea .ea -se .w .ao
TAI RATS .taeee .e»oea .oeeae .oaeoa .aeeae
TAX LIABILITY -BO .00 .88 .M .08
iNvesTKvr TAI car. .a* .aa .ee .aa .aa
niNtnun TAI .ea .ee .aa .aa .00
TOTAL TAX DUE .88 .89 . efl .aa ' .88
EARNINGS «TER TAX -«11.4a -US3.il -881. »S -434.7B -4«;.9a
DEPRECIATION 5^.«a ai:.ae ua.:7 ua.42 ir:.:r
DEPLETION .ee .ea -so .aa .00
CASH PLON »CF.9EDT. -578. «O -J4a." -3O:.ii -:i..B8 -S7.4J
REO. PRINCIPAL 2=».M K1.S7 2=.77 2I..8B 2M.»
sia.cap.Eip. . .aa .ea .ee .ee .aa
XTRA.CASH IN-FLOUS .aa .ea .ae .aa .oe
HORK.CAP.RECOVCRT .88 -M .80 .ea .00
NET CASH FLO* -*87.I8 -171.8» -337. IJ -IBS.08 —4*3.4»
DISCOUNT FACTOR .»CBtJ .8*333 .884** .74883 .*9&:*
DSCT.NCT CASH FLOW -3*3.81 -4*4.87 -432.J7 -ITS.»4 -524.38
YEAR * 7 8 *
REVENUES 33a.ee 334.ae see.aa *a*.eo
ou, COSTS 7e3.ee 7a3.ee 7es.ee Tes.aa
DEPRECIATION .88 .88 .88 .Be
INTEREST M.43 .ae .ea .aa
CONTROL Otff COSTS .88 .88 .88 .88
EARNINGS »EFORE TAX -18*.43 -ISI.ea -123.88 -**.88
DEPLETION .88 .88 .88 .88
TAX LOSS .ea .ea .ea .ea
TAX RATE .88888 .80808 .88888 .88833
TAX LIABILITY . .88 .88 .88 .88
INVESTMENT TAX COT. .88 .88 .88 .88 .83
HINtnUH TAX .88 .88 .88 .88 .88
TOTAL TAI DUE .88 . »a .99 .88 .8a
EARNINSS AFTER TAX -18».43 -131.88 -123.88 -**.88 -71.88
DEPRECIATION .88 .88 .88 .88 .88
DEPLETION .88 .88 .88 .08 .88
CASH FUOU KP.DCaT. -18*.43 -131.88 -123.88 -**.88 -71.88
R£3. PRINCIPAL 248.31 .88 .88 .88 .88
Sua.CAP.EXP. .88 .88 .88 .30 .83
XTRA.CASH IN-FLOUS .88 .88 .88 .88 .83
UORK.CAP.RECOVERY .88 .88 .83 .88 .88
NET CASH FLOU -42*.«4 -131.W -123.88 -»*.83 -71.38
DISCOUNT FACTOR .*47*» .*O27» .3*a7a .32133 .48319
08CT.NET CASH FLON -278.3* -91.82 -78.8* -31.»4 -J4.43
YEAR 11 12
REVENUES k3J.ee *34.«e
Oin COSTS 783.88 7es.ea
DEPRECIATION .88 .88
INTEREST .88 .88
CONTROL Otn COSTS .88 .88
EARNINGS *EFORE TAI -71.88 -7:. BO
DEPLETION .88 .88
TAX LOSS .88 .88
TAX RATE .eeeee .•eaoa
TAX LIA8ILITY .88 .88
INVESTMENT TAX COT. .88 .88
nlNIHUN TAI .88 .88
TOTAL TAI DUE .88 .88
EARNINGS AFTER TAX -71.88 -71.88
DEPRECIATION .ee .ee
DEPLETION .ea .88
CASH FLOH tEP.SCDT. ' -71.88 -71.88
REG. PRINCIPAL .ae .ae
SUS.CAP.EXP. .ea .ee
ITRA.CASH IN-FLOUS .88 333.88
•ORK. COP. RECOVERY .80 3=3.33
NET CASH FLOU -71.80 *»S.88
DISCOUNT FACTOR .43134 .41*8*
DSCT.NET CASH FLOU -32.83 417.7*
PRESENT VALUE OF CASH FLOKS FOR 12 YSARS IS
LESS EQUITY SHARE OF ORIGINAL INVESTMENT
MET PRESENT VALUE IS
THE 1RR IS .28 PERCENT
SINCE «oR>;if«5 CAPITAL is pecovweo IT is
A-25
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net present value ($-3932.65 thousand). The third situation is shown on
Table A.16. Here the 2 LT/D, 5% acid gas, 2% sour gas case is economically
feasible under Regulatory Alternative III with a positive net present value
of $1865.15 thousand. In this situation, there is no need to run the DCF
model for the baseline case since the costs are less than under the NSPS
case.
In total, 27 plants were found to be economically feasible under the
baseline conditions, but economically infeasible under Regulatory Alter-
native III. The data for these 27 plants were transformed into ranges of
facility size, H£S concentrations in the acid gas, and H2S concentrations
in the sour gas. These plants are identified in Table A.17. As can be
seen on this table the aggregate probabilities range from .0140 to .0799.
These low probabilities indicate that plants with these gas quality
combinations have a very low probability of being developed. If these
aggregate probabilities by size categories are then multiplied by the
number of facilities projected between 1985-1995 for each size category,
the number of expected impacted facilities can be observed. Over the ten
year period of this analysis the total number of expected adversely impacted
facilities, for all size categories, i.s 4.4. If these expected new facilities
were in fact not built due to the adverse economic affects of the NSPS it
would amount to approximately 1.4 X 10^ SCF/year of sweet gas curtailed
over the lu year period. To put this in perspective the potential gas
curtailed amounts to .01% of the projected total new gas production of
approximately 10,000 X 10y SCF/year.
The basic conclusion of this analysis is that the NSPS is not expected
to cause the delay or cancellation of onshore processing facilities currently
projected to be constructed over the next ten years. Although the analysis
has identified a limited number of situations in which the NSPS would
preclude the development of otherwise economically feasible facilities, it
is highly unlikely that new facilities will display sulfur content levels
similar to those model plants shown to be adversely affected.
A-26
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TABLE A.16.
2LT/DAY. sx AC:D SAS. 2r. JOUR SAS
DISCOUNTE3 CASH FLOU ANALYSIS 'Of ALTERNATIVE III
ANALYSIS IN CONSTANT DOLLARS (UNITS EXPRESSES AS THOUSANDS OF 1984 DOLLARS)
ICU FINAKIN6, PERCENT D69T 33.80 IMVSSTMSNTl EOUtPrSNT 2447.80
PERCENT COUITY sa.ee (UILDINGS .ea
DESCENT CKT.D8T. .Da LAND .80
PERCENT CMT.IO. .88 MORI-'INO Cif. S2S.30
CNT.EOUIP. .80
«AR 1 2 3 4 S
REVBNUES 1211.38 t247.ea 1225.80 iia*.e8 n*a. aa
otn COSTS 7oi.ec 7M.ee 7es.ea 73:.ee 733.aa
DEPRECIATION sr:.4a 812.88 ssa.37 5*8.4: 173.31
INTEREST 94.83 78.32 4i.ii ts.ee 29 4:
CONTROL otn COSTS .00 .aa .83 .ea oo
SMNima IEFORS TA» -i;j.«a -ICT.I: -:t.»j 147.10 540.92
XPUTTIOM ,M .oe .ea .ca ' .go
TA» LOSS .ee .oe .00 -147.ra -:ar.u
TAX RATE .eaeca .aeeea .oooca .eesoa .»J9i?
TAI LIABILITY .80 .00 .00 .30 14°.SI
INVESTWNT TAX CST. .09 .00 .00 .00 1:8.34
niNinun TAX ,ee .09 .ao ao eo
TOTAL TAX OU6 .00 . N .98 .SO IS.08
EAHNtNSS AFTER TAX -::J.40 -^9.11 -21.91 147. Z3 II1.;4
DEPRECIATION C:.4a 81C.BO S80.S7 MS.a: 171.K
ae>irriON .to .aa .00 .ea .00
CASH »uou tar-oeoT. 410.ao 483.48 ira.w 4:1.92 4*4.88
wa. w(iNCt(>Au 2=9.18 tn.rr 1:3.77 :;*.ee 2^.:s
3U3.CAP.EXP. .BO .00 .OO .aO .80
XTRA.CASH IN^n.OUS .00 .OO .BO .03 .30
MORK.CAP.KSCavERr .00 .DO .03 .BO .03
MET CASH H.OK 183.42 =2.11 124.07 3»».92 418.41
DISCOUNT FACTOR .»;O2; .«4SSS .«84»4 .74880 .49414
OSCT.MtT CASH FLOM 140.02 218.14 241.SI 299.4* 319.4*
* 7 8 9 18
1:17.00 iss*.ao 14:9.00 i7^*.aa 1814. ao
TBS.aa 703.00 703. aa Tts.eo 701.30
H .00 .eo .aa • . eo .eo
INTEREST M.43 .00 .aa .eo .ea
CONTROL can COSTS .eo .BO .aa .aa .aa
EARNINGS UFORE TAI 797. 77 881. 8a 9S4.a3 18JI.OO 1111.00
TAX LOSS .aa .aa .aa .03 .eo
TAX RATE .48441 .48731 .48877 .493^4 .4°177
TAI LIABILITY 384.31 429.34 4*4.29 S3:.34 S44.74
INVCSTMENT TAI COT. M.ik .BO .03 .83 .83
RlNlrun TAX .00 .83 .03 .93 .80
TOTAL TAX DUE 382.1: 429.84 4*4.29 'ZK.Z* S44. ib
CARMINES ATTER TAX 491.42 4S1.94 487.71 III. 44 S.4.44
DCPHECIATION .83 .88 .83 .80 .03
DEPICTION .83 .83 .83 .83 .83
CASH FLOW (CF-OCDT. 493.42 411.94 487.71 121. 44 3*4.44
RE3. PRINCIPAL 248.31 .03 .83 .09 .89
SU3.CAP.CXP. .80 .83 ,a8 .83 .83
ITRA.CASH iN-n.ows .aa .aa .ea .ao .ao
MET CASH FLOW ' 214.98 451.94 487.71 Z23.44 3*4.44
DISCOUNT FACTOR .44744 .48274 .3*373 .321:3 ,48:i«
DSCT. NET CASH FLOW 1*3.17 272.41 272.4* 274.8* 27;. 94
WAR 11 12
REVENUES 1814.ea 1814.aa
Old COSTS 701.30 783.93
DEPRECIATION .83 .80
INTEREST .aa .89
CONTROL 0*H COSTS .88 .88
EARNlNOS tEFORE TAX 1111.88 1111.88
. DEPLETION .83 .83
TAX LOSS .83 .88
TAX RATE .49177 .49177
TAX LIABILITY 34*.;* 34*.!*
INVESTMENT TAX COT. ,8a .89
nlNinun TAI .ae .aa
TOTAL TAX DUE S4*.3* 344.3*
EARN I NO« AFTER TAX 3*4.44 54-1.44
.DEPRECIATION .88 .83
DEPLETION .aa .aa
CASH FLOW IEF.DEDT. I4-J.44 3*4.*4
RE3. PRINCIPAL .88 .99
SUS.CAP.EXP. .83 .83
XTRA.CASH IN-FLOUS .89 3^.88
MORK. CAP. RECOVERY . 8a SCC.OB
NET CASH FLOW 3*4.44 14C8.44
DISCOUNT FACTOR .41114 .41984
OSCT.NET CASH FLOW 2=4.33 484.4C
PRESENT VALUE OF CASH FLOWS FOR 12 YEARS IS
LC3S EOUITY SHARE OF ORIGINAL INVESTMENT
NET PRESENT VALUE IS
THE IRR IS :a.«0 CERCENT
SINCE HOIKING CAPITAL IS RECOVERED IT IS
THAT THS PROJECT, TERntNATSS AT THS END 0" THE
A-27
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I/
TABLE A.17 SUMMARY OF PLANTS MADE ECONOMICALLY INFEAS1BLE BY REGULATORY ALTERNATIVE III
3=
I
oo
Average Sweet Gas
Flow uer Faci lity
10^ SCF/Y
0.2244
U.2673
0.3b6b
U.41b5
0.3107
0.4861
Facil
LT/d
1.08-1.97
2.07-2.95
3.05-3.94
4.U4-4.92
5.02-9.04
39.27-49.2
ity Size
Mg/d
1.1-2.0
2.1-3.0
3.1-4.0
4.1-5.0
5.1-8.0
40.1-60
Mole
Acid
Gas
2-50
2-20
2-20
2-12.5
2-100.0
12.5-50
% H2S
Sour
Gas
2-12.5
2-12.5
2-12.5
2-5
2-12.5
.0 12.5-20
Maximum
Probability
0.0301
0.0260
0.0342
0.0140
0.0799
.0 0.0392
10 Year
Projected #
Facilities
16.5
11.5
10.5
9.5
37.0
3.2
Potentially
Affected #
Facilities
0.497
0.308
0.359
0.133
2.956
0.125
Sweet Gas
Flow
H)9 SCF/Y
0.111
0.082
0.128
0.055
0.918
0.061
Total
0.2102
4.378
1.355
I/ See docket entry IV-B-28 for detail on the sour yas characteristic frequency distributions.
-------
REFERENCES FOR APPENDIX A
1. State Tax Gu1de - All States, Volume 2, Commerce Clearing House, Inc.,
1984.
2. Chase Energy Economics, Financial Analysis of a Group of Petroleum
Companies, 1981, p. 25. Docket No. A-80-20-A.
3. Personal communication between Janet Scheid of U.S.E.P.A. with Dr.
Edward Erickson, North Carolina State University, January 1985.
A-29
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TECHNICAL REPORT DATA
(Please read Instructions on the reverse before completing)
REPORT NO.
EPA-450/3-82-023b
3. RECIPIENT'S ACCESSION NO.
4. TITLE AND SUBTITLE
S02 Emissions in Natural Gas Production Industry
Background Information for Promulgated Standards
5. REPORT DATE
September 1985
6. PERFORMING ORGANIZATION CODE
. AUTHOR(S)
8. PERFORMING ORGANIZATION REPORT NO.
9. PERFORMING ORGANIZATION NAME AND ADDRESS
Office of Air Quality Planning and Standards
U. S. Environmental Protection Agency
Research Triangle Park, N.C. 27711
10. PROGRAM ELEMENT NO.
11. CONTRACT/GRANT NO.
68-02-3063
12. SPONSORING AGENCY NAME AND ADDRESS
Director for the Office of Air Quality Planning
and Standards
Office of Air and Radiation , U.S. EPA
Research Triangle Park, N.C. 27711
13. TYPE OF REPORT AND PERIOD COVERED
14. SPONSORING AGENCY CODE
EPA/200/04
is. SUPPLEMENTARY NOTES This document presents the background information used by the
Environmental Protection Agency in developing the final new source performance standard
for emissions of sulfur dioxide from the natural gas processing industry.
16. ABSTRACT
Standards of performance for the control of sulfur dioxide (S02) emissions from
the natural gas processing industry are being promulgated under Section 111 of the
Clean Air Act. These standards will apply to S02 emissions from newly constructed,
modified, and reconstructed sweetening and sulfur recovery units in onshore
natural gas processing plants. This document summarizes the responses to public
comments received on .the proposed standards and the basis for changes made since
proposal.
17.
KEY WORDS AND DOCUMENT ANALYSIS
a.
DESCRIPTORS
b.lDENTIFIERS/OPEN ENDED TERMS
c. COSATi field/Group
Air Pollution
Natural Gas Processing
Pollution Control
Standards of Performance
Sulfur Dioxide (S02)
Air Pollution Control
13b
is. DISTRIBUTION STATEMENT
Unlimited - Available to the public free
of charge from U.S. EPA Library (MD-35)
Research Triangle Park, N.C. 27711
19. SECURITY CLASS (Tins Report/
Unclassified
120. SECURITY CLASS tTHispagei
Unclassified
21. NO. OF PAGES
137
22. PRICE
EPA Form 2220-1 (R«v. 4-77) PREVIOUS EDITION is OBSOLETE
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