REGULATORY
IMPACT
ANALYSIS
FOR
THE
PETROLEUM
REFINERY
NESHAP
REVISED
DRAFT
FOR
PROMULGATION
Office
of
Air
Quality
Planning
and
Standards
U.
S.
Environmental
Protection
Agency
Research
Triangle
Park,
NC
27711
July
1995
iii
CONTENTS
Page
TABLES
.
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vi
FIGURES
.
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vii
ACRONYMS
AND
ABBREVIATIONS
.
.
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.
.
viii
EXECUTIVE
SUMMARY
.
.
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.
ES­
1
ES.
1
PURPOSE
AND
STATUTORY
AUTHORITY
.
.
.
.
.
.
.
.
.
ES­
1
ES.
2
PROPOSED
PETROLEUM
REFINERY
EMISSION
STANDARD
.
.
ES­
2
ES.
3
NEED
FOR
REGULATION
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
ES­
3
ES.
4
CONTROL
TECHNIQUES
AND
REGULATORY
ALTERNATIVES
.
ES­
4
ES.
5
COST
ANALYSIS
.
.
.
.
.
.
.
.
.
.
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.
.
.
.
.
.
.
ES­
4
ES.
6
ECONOMIC
IMPACTS
AND
SOCIAL
COSTS
.
.
.
.
.
.
.
.
ES­
6
ES.
7
QUALITATIVE
ASSESSMENT
OF
BENEFITS
OF
EMISSION
REDUCTIONS
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
ES­
8
ES.
8
QUANTITATIVE
ASSESSMENT
OF
BENEFITS
.
.
.
.
.
.
.
ES­
8
ES.
9
COMPARISON
OF
BENEFITS
TO
COSTS
.
.
.
.
.
.
.
.
.
ES­
10
1.0
INTRODUCTION
.
.
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1
1.1
PURPOSE
.
.
.
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.
.
1
1.2
LEGAL
HISTORY
AND
STATUTORY
AUTHORITY
.
.
.
.
.
.
.
2
2.0
PROPOSED
PETROLEUM
REFINERIES
EMISSION
STANDARD
IN
BRIEF
5
2.1
THE
EMISSION
STANDARD
IN
BRIEF
.
.
.
.
.
.
.
.
.
.
5
2.1.1
Applicability
of
the
Petroleum
Refinery
NESHAP
.
6
2.1.2
Miscellaneous
Process
Vent
Provisions
.
.
.
.
.
6
2.1.3
Storage
Vessel
Provisions
.
.
.
.
.
.
.
.
.
.
.
7
2.1.4
Wastewater
Provisions
.
.
.
.
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.
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8
2.1.5
Equipment
Leak
Provisions
.
.
.
.
.
.
.
.
.
.
.
8
2.1.6
Recordkeeping
and
Reporting
Provisions
.
.
.
.
.
9
2.1.7
Emission
Averaging
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
9
3.0
NEED
FOR
REGULATION
.
.
.
.
.
.
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.
.
.
.
.
11
3.1
MARKET
FAILURE
.
.
.
.
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.
.
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.
.
.
.
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.
.
11
3.1.1
Air
Pollution
as
an
Externality
.
.
.
.
.
.
.
.
12
3.1.2
Natural
Monopoly
.
.
.
.
.
.
.
.
.
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.
.
.
.
.
.
12
3.1.3
Inadequate
Information
.
.
.
.
.
.
.
.
.
.
.
.
.
13
3.2
INSUFFICIENT
POLITICAL
AND
JUDICIAL
FORCES
.
.
.
.
13
3.3
ENVIRONMENTAL
FACTORS
WHICH
NECESSITATE
REGULATION
14
3.3.1
Air
Emission
Characterization
.
.
.
.
.
.
.
.
.
14
3.3.2
Harmful
Effects
of
HAPs
.
.
.
.
.
.
.
.
.
.
.
.
15
3.4
CONSEQUENCES
OF
REGULATORY
ACTION
.
.
.
.
.
.
.
.
.
17
3.4.1
Consequences
if
EPA's
Emission
Reduction
Objectives
are
Met
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
17
3.4.2
Consequences
if
EPA's
Emission
Reduction
Objectives
are
Not
Met
.
.
.
.
.
.
.
.
.
.
.
.
.
.
20
4.0
CONTROL
TECHNIQUES
AND
REGULATORY
ALTERNATIVES
.
.
.
.
.
23
4.1
CONTROL
TECHNIQUES
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
24
CONTENTS
(
continued)

Page
iv
4.1.1
Combustion
Technology
.
.
.
.
.
.
.
.
.
.
.
.
.
24
4.1.2
Product
Recovery
Devices
.
.
.
.
.
.
.
.
.
.
.
.
36
4.1.3
Leak
Detection
and
Repair
.
.
.
.
.
.
.
.
.
.
.
52
4.1.4
Internal
Floating
Roofs
.
.
.
.
.
.
.
.
.
.
.
.
62
4.2
DESCRIPTION
OF
MACT
AND
SUMMARY
OF
REGULATORY
ALTERNATIVES
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
65
4.2.1
Miscellaneous
Process
Vents
.
.
.
.
.
.
.
.
.
.
66
4.2.2
Storage
Vessels
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
66
4.2.3
Wastewater
Streams
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
67
4.2.4
Equipment
Leaks
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
68
4.2.5
Summary
of
Alternatives
.
.
.
.
.
.
.
.
.
.
.
.
69
4.3
NO
ADDITIONAL
EPA
REGULATION
.
.
.
.
.
.
.
.
.
.
.
69
4.3.1
Judicial
System
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
69
4.3.2
State
and
Local
Action
.
.
.
.
.
.
.
.
.
.
.
.
.
71
4.4
ROLE
OF
COST
EFFECTIVENESS
IN
CHOOSING
AMONG
REGULATORY
ALTERNATIVES
.
.
.
.
.
.
.
.
.
.
.
.
.
.
71
4.5
ECONOMIC
INCENTIVES:
SUBSIDIES,
FEES,
AND
MARKETABLE
PERMITS
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
72
5.0
COST
ANALYSIS
AND
EMISSION
REDUCTION
.
.
.
.
.
.
.
.
.
.
75
5.1
APPROACH
FOR
ESTIMATING
REGULATORY
COMPLIANCE
COSTS
75
5.1.2
Calculations
for
Existing
Sources
.
.
.
.
.
.
.
77
5.1.3
Calculations
for
New
Sources
.
.
.
.
.
.
.
.
.
.
84
5.2
TOTAL
COMPLIANCE
COST
ESTIMATES,
REDUCTIONS,
AND
COST
EFFECTIVENESS
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
87
5.3
MONITORING,
RECORDKEEPING,
AND
REPORTING
COSTS
.
.
91
6.0
ECONOMIC
IMPACTS
AND
SOCIAL
COSTS
.
.
.
.
.
.
.
.
.
.
.
97
6.1
PROFILE
OF
THE
PETROLEUM
REFINING
INDUSTRY
.
.
.
.
.
98
6.1.1
Profile
of
Affected
Facilities
.
.
.
.
.
.
.
.
.
99
6.1.2
Market
Structure
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
102
6.1.3
Market
Supply
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
106
6.1.4
Market
Demand
Characteristics
.
.
.
.
.
.
.
.
.
107
6.1.5
Market
Outlook
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
111
6.2
MARKET
MODEL
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
114
6.2.1
Market
Supply
and
Demand
.
.
.
.
.
.
.
.
.
.
.
.
114
6.2.2
Market
Supply
Shift
.
.
.
.
.
.
.
.
.
.
.
.
.
.
115
6.2.3
Impact
of
Supply
Shift
on
Market
Price
and
Quantity
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
119
6.2.4
Trade
Impacts
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
119
6.2.5
Changes
in
Economic
Welfare
.
.
.
.
.
.
.
.
.
.
120
6.2.6
Labor
Market
and
Energy
Market
Impacts
.
.
.
.
.
123
6.2.7
Baseline
Inputs
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
124
6.2.8
Price
Elasticities
of
Demand
and
Supply
.
.
.
.
124
6.3
CAPITAL
AVAILABILITY
ANALYSIS
.
.
.
.
.
.
.
.
.
.
.
127
6.4
LIMITATIONS
OF
THE
ECONOMIC
MODEL
.
.
.
.
.
.
.
.
.
131
6.5
PRIMARY
IMPACT,
CAPITAL
AVAILABILITY
ANALYSIS,
AND
SECONDARY
IMPACT
RESULTS
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
133
6.5.1
Estimates
of
Primary
Impacts
.
.
.
.
.
.
.
.
.
.
133
6.5.2
Capital
Availability
Analysis
.
.
.
.
.
.
.
.
.
136
CONTENTS
(
continued)

Page
v
6.5.3
Labor
Market
Impacts
and
Energy
Market
Impacts
.
137
6.5.4
Foreign
Trade
Impacts
.
.
.
.
.
.
.
.
.
.
.
.
.
139
6.5.5
Regional
Impacts
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
140
6.6
SUMMARY
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
140
6.7
POTENTIAL
SMALL
BUSINESS
IMPACTS
.
.
.
.
.
.
.
.
.
142
6.7.1
Introduction
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
142
6.7.2
Methodology
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
142
6.7.3
Categorization
of
Small
Businesses
.
.
.
.
.
.
143
6.7.4
Small
Business
Impacts
.
.
.
.
.
.
.
.
.
.
.
.
.
143
6.8
SOCIAL
COSTS
OF
REGULATION
.
.
.
.
.
.
.
.
.
.
.
.
144
6.8.1
Social
Cost
Estimates
.
.
.
.
.
.
.
.
.
.
.
.
.
144
7.0
QUALITATIVE
ASSESSMENT
OF
BENEFITS
OF
EMISSION
REDUCTIONS
149
7.1
IDENTIFICATION
OF
POTENTIAL
BENEFIT
CATEGORIES
.
.
149
7.2
QUALITATIVE
DESCRIPTION
OF
AIR
RELATED
BENEFITS
.
.
150
7.2.1
Benefits
of
Decreasing
HAP
Emissions
.
.
.
.
.
.
150
7.2.2
Benefits
of
Reduced
VOC
Emissions
.
.
.
.
.
.
.
153
8.0
QUANTITATIVE
ASSESSMENT
OF
BENEFITS
.
.
.
.
.
.
.
.
.
.
157
8.1
METHODOLOGY
FOR
DEVELOPMENT
OF
BENEFIT
ESTIMATES
.
157
8.1.1
Benefits
of
Reduced
Cancer
Risk
Associated
with
HAP
Reductions
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
158
8.1.2
Quantitative
Benefits
of
VOC
Reduction
.
.
.
.
.
165
9.0
COMPARISON
OF
BENEFITS
TO
COSTS
.
.
.
.
.
.
.
.
.
.
.
.
173
9.1
COMPARISON
OF
ANNUAL
BENEFITS
AND
COSTS
.
.
.
.
.
.
173
vi
TABLES
Page
ES­
1
SUMMARY
OF
TOTAL
COSTS
IN
THE
FIFTH
YEAR
FOR
THE
PETROLEUM
REFINING
INDUSTRY
REGULATION
.
.
.
.
.
.
.
ES­
5
ES­
2
ANNUAL
SOCIAL
COST
ESTIMATES
FOR
THE
PETROLEUM
REFINING
REGULATION
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
ES­
7
ES­
3
VOC
EMISSION
REDUCTIONS
BY
EMISSION
POINT
.
.
.
.
.
ES­
9
ES­
4
BENEFIT
PER
MEGAGRAM
VALUES
FOR
VOC
REDUCTIONS
.
.
.
ES­
10
ES­
5
COMPARISON
OF
ANNUAL
BENEFITS
TO
COSTS
FOR
THE
NATIONAL
PETROLEUM
REFINING
INDUSTRY
REGULATION
.
.
.
.
.
.
.
ES­
11
ES­
6
VOC
INCREMENTAL
COST­
EFFECTIVENESS
OF
PETROLEUM
REFINING
REGULATION
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
ES­
11
3­
1
NATIONAL
BASELINE
VOC
AND
HAP
EMISSIONS
BY
EMISSION
POINT
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
15
3­
2
BASELINE
SPECIATED
HAP
EMISSIONS
FROM
EQUIPMENT
LEAKS
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
16
3­
3
NATIONAL
CONTROL
COST
IMPACTS
OF
PREFERRED
ALTERNATIVE
IN
THE
FIFTH
YEAR
.
.
.
.
.
.
.
.
.
.
.
19
4­
1
SUMMARY
OF
REGULATORY
ALTERNATIVES
BY
EMISSION
POINT
70
5­
1
SUMMARY
OF
TOTAL
COSTS
IN
THE
FIFTH
YEAR
FOR
THE
PETROLEUM
REFINING
NESHAP
.
.
.
.
.
.
.
.
.
.
.
.
.
88
5­
2
CONTROL
OPTIONS
AND
IMPACTS
BY
EMISSION
POINT
.
.
.
89
5­
3
COST,
HAP
EMISSION
REDUCTION,
AND
COST
EFFECTIVENESS
BY
ALTERNATIVE
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
90
5­
4
COST,
VOC
EMISSION
REDUCTION,
AND
COST
EFFECTIVENESS
BY
ALTERNATIVE
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
90
5­
5
MISCELLANEOUS
PROCESS
VENTS
C
MONITORING,
RECORDKEEPING,
AND
REPORTING
REQUIREMENTS
FOR
COMPLYING
WITH
98
WEIGHT­
PERCENT
REDUCTION
OF
TOTAL
ORGANIC
HAP
EMISSIONS
OR
A
LIMIT
OF
20
PARTS
PER
MILLION
BY
VOLUME
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
93
6­
1
ESTIMATES
OF
PRICE
ELASTICITY
OF
DEMAND
.
.
.
.
.
.
125
6­
2
SUMMARY
OF
PRIMARY
IMPACTS
.
.
.
.
.
.
.
.
.
.
.
.
135
6­
3
ANALYSIS
OF
FINANCIAL
RATIOS
.
.
.
.
.
.
.
.
.
.
.
137
6­
4
SUMMARY
OF
SECONDARY
REGULATORY
IMPACTS
.
.
.
.
.
.
138
6­
5
FOREIGN
TRADE
(
NET
EXPORTS)
IMPACTS
.
.
.
.
.
.
.
.
141
6­
6
ANNUAL
SOCIAL
COST
ESTIMATES
FOR
THE
PETROLEUM
REFINING
REGULATION
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
145
7­
1
POTENTIAL
HEALTH
AND
WELFARE
EFFECTS
ASSOCIATED
WITH
EXPOSURE
TO
HAZARDOUS
AIR
POLLUTANTS
.
.
.
.
.
.
.
151
8­
1
HAP
EMISSIONS
AT
PETROLEUM
REFINERIES
.
.
.
.
.
.
.
158
8­
2
SOURCES
OF
UNCERTAINTY
IN
CANCER
RISK
ASSESSMENT
.
161
8­
3
UNCERTAINTIES
IN
BENEFIT
ANALYSIS
.
.
.
.
.
.
.
.
.
161
8­
4
UNIT
RISK
FACTORS
FOR
CARCINOGENIC
HAPS
.
.
.
.
.
.
162
8­
5
MAXIMUM
INDIVIDUAL
RISK
AND
ANNUAL
CANCER
INCIDENCE
OF
CARCINOGENIC
HAPs
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
163
8­
6
RFCS
AND
NUMBER
OF
INDIVIDUALS
EXPOSED
AT
OR
ABOVE
RFC
BY
HAP
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
164
8­
7
VOC
EMISSION
REDUCTIONS
BY
EMISSION
POINT
.
.
.
.
.
169
8­
8
BENEFITS
OF
VOC
REDUCTIONS
BY
REGULATORY
ALTERNATIVE
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
170
8­
9
VOC
INCREMENTAL
COST­
EFFECTIVENESS
OF
PETROLEUM
REFINING
REGULATION
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
171
vii
9­
1
COMPARISON
OF
ANNUAL
BENEFITS
TO
COSTS
FOR
THE
NATIONAL
PETROLEUM
REFINING
INDUSTRY
REGULATION
.
.
175
FIGURES
Page
6­
1
ILLUSTRATION
OF
POST­
NESHAP
MODEL.
.
.
.
.
.
.
.
118
viii
ACRONYMS
AND
ABBREVIATIONS
API
American
Petroleum
Institute
ASM
Annual
Survey
of
Manufactures
bbl
One
barrel;
equal
to
42
gallons
bbl/
d
barrels
per
day
BCA
Benefit
Cost
Analysis
BWON
Benzene
Waste
Operations
NESHAP
(
NESHAP
is
defined
below)
CAA
Clean
Air
Act
Amendments
of
1990
C/
E
cost
effectiveness
CERA
Cambridge
Energy
Research
Associates
DOC
Department
of
Commerce
DOE/
EIA
Department
of
Energy/
Energy
Information
Administration
EIA
economic
impact
analysis
EPA
Environmental
Protection
Agency
FCCU
fluidized
catalytic
cracking
unit
HAP
Hazardous
Air
Pollutant
HEM
Human
Exposure
Model
HON
Hazardous
Organic
NESHAP
(
NESHAP
is
defined
below)
IARC
International
Agency
for
Research
on
Cancer
kPa
kilopascal
LDAR
leak
detection
and
repair
LEL
lower
explosive
limit
LPGs
Liquefied
Petroleum
Gases
lpm
liter
per
minute
MACT
Maximum
Achievable
Control
Technology
MIR
maximum
individual
risk
MRR
monitoring,
recordkeeping,
and
reporting
MTBE
Methyl
tertiary
butyl
ether
Mg
Megagram
NAAQS
National
Ambient
Air
Quality
Standard
NESHAP
National
Emission
Standard
for
Hazardous
Air
Pollutants
NSPS
New
Source
Performance
Standard
NO
x
nitrogen
oxide
OGJ
Oil
and
Gas
Journal
OMB
Office
of
Management
and
Budget
PADD
Petroleum
Administration
for
Defense
Districts
ppmv
parts
per
million
by
volume
RACT
Reasonably
Available
Control
Technology
RFA
Regulatory
Flexibility
Act;
also
Regulatory
Flexibility
Analysis
RfC
reference­
dose
concentration
RIA
Regulatory
Impact
Analysis
SIC
Standard
Industrial
Classification
SIP
State
Implementation
Plan
SO
2
sulfur
dioxide
SOCMI
Synthetic
Organic
Chemical
Manufacturing
industry
URF
unit
risk
factor
VOC
volatile
organic
compound
ES­
1
EXECUTIVE
SUMMARY
ES.
1
PURPOSE
AND
STATUTORY
AUTHORITY
This
report
analyzes
the
regulatory
impacts
of
the
Petroleum
Refinery
National
Emission
Standard
for
Hazardous
Air
Pollutants
(
NESHAP),
which
is
being
promulgated
under
Section
112
of
the
Clean
Air
Act
Amendments
of
1990
(
CAA).
This
emission
standard
would
regulate
the
emissions
of
certain
hazardous
air
pollutants
(
HAPs)
from
petroleum
refineries.
The
petroleum
refineries
industry
group
includes
any
facility
engaged
in
the
production
of
motor
gasoline,
naphthas,
kerosene,
jet
fuels,
distillate
fuel
oils,
residual
fuel
oils,
lubricants,
or
other
products
made
from
crude
oil
or
unfinished
petroleum
derivatives.
This
report
analyzes
the
impact
that
regulatory
action
is
likely
to
have
on
the
petroleum
refining
industry,
and
on
society
as
a
whole.

The
President
issued
Executive
Order
12866
on
October
4,
1993,

which
requires
EPA
to
prepare
RIAs
(
or
economic
assessments)
for
all
"
significant"
regulatory
actions.
At
proposal,
EPA
determined
that
the
petroleum
refinery
NESHAP
is
a
"
significant"

rule
because
it
had
an
estimated
annual
cost
on
the
economy
of
more
than
$
100
million,
and
is
therefore
subject
to
the
requirements
of
Executive
Order
12866.
As
shown
later
in
the
report,
that
cost
is
now
less
than
$
100
million,
but
it
has
been
decided
that
due
to
the
level
of
interest
in
the
results
of
the
analyses
that
make
up
this
report
that
revising
the
RIA
for
promulgation
was
necessary.
This
report
satisfies
the
requirements
of
the
executive
order.
In
addition
to
a
mandatory
assessment
of
benefits
and
costs,
E.
O.
12866
specifies
that
EPA,

to
the
extent
allowed
by
the
CAA
and
court
orders,
demonstrate
ES­
2
(
1)
that
the
benefits
of
the
NESHAP
regulation
will
outweigh
the
costs
and
(
2)
that
the
maximum
level
of
net
benefits
(
including
potential
economic,
environmental,
public
health
and
safety
and
other
advantages;
distributive
impacts;
and
equity)
will
be
reached.
EPA
has
chosen
two
regulatory
options
to
be
evaluated
in
this
RIA.
For
each
of
the
two
options,
benefits
and
costs
are
quantified
to
the
greatest
extent
allowed
by
available
data.

The
petroleum
refinery
NESHAP
would
require
sources
to
achieve
emission
limits
reflecting
the
application
of
the
maximum
achievable
control
technology
(
MACT),
consistent
with
sections
112(
d)
and
112(
h)
of
the
CAA.
Section
112
of
the
CAA
provides
a
list
of
189
HAPs
and
directs
the
EPA
to
develop
rules
to
control
HAP
emissions.
For
the
Petroleum
Refinery
NESHAP,
EPA
chose
regulatory
options
based
on
control
options
on
an
emission
point
basis.
An
emission
point
is
defined
as
a
point
within
a
refinery
which
emits
one
or
more
HAPs.
The
emission
points
to
be
regulated
under
the
source
category
for
this
standard
are:

equipment
leaks,
storage
vessels,
miscellaneous
process
vents,

and
wastewater
collection
and
treatment
systems.

ES.
2
PROMULGATED
PETROLEUM
REFINERY
EMISSION
STANDARD
The
promulgated
rule,
the
Petroleum
Refinery
NESHAP,
would
require
sources
to
achieve
emission
limits
reflecting
the
application
of
MACT.
The
definition
of
source
in
the
proposed
standard
is
"
the
collection
of
emission
points
in
HAP­
emitting
petroleum
refining
processes
within
the
source
category."
The
source
comprises
all
miscellaneous
process
vents,
storage
vessels,
wastewater
collection
and
treatment
systems,
and
equipment
leaks
associated
with
petroleum
refining
process
units
that
are
located
at
a
single
plant
site
covering
a
contiguous
area
under
common
control.
The
definition
of
source
is
an
important
element
of
this
NESHAP
because
it
describes
the
specific
grouping
of
emission
points
within
the
source
category
to
which
each
standard
applies.
The
rule
is
made
up
of
seven
different
subjects:
applicability,
definitions,
and
general
ES­
3
standards;
miscellaneous
process
vent
provisions;
storage
vessel
provisions;
wastewater
provisions;
equipment
leak
provisions;

recordkeeping
and
reporting
provisions;
and
emissions
averaging.

The
promulgated
rule
outlines
the
chosen
option
for
controlling
HAP
emissions
from
each
of
the
four
emission
points
within
a
refinery
source,
given
existing
control
technology.

The
applicability
of
the
rule
refers
to
the
definition
of
the
source
within
the
petroleum
refinery
source
category.
The
emission
standard
applies
to
petroleum
refining
process
units
that
are
part
of
a
major
source
as
defined
in
Section
112
of
the
CAA.
EPA's
initial
source
category
list
(
57
FR
31576,

July
16,
1992),
required
by
section
112(
c)
of
the
Act,
identifies
categories
of
sources
for
which
NESHAP
are
to
be
established.

Two
categories
of
sources
are
listed
in
the
initial
source
category
list
for
petroleum
refineries:
(
1)
catalytic
cracking
(
fluid
and
other)
units,
catalytic
reforming
units,
and
sulfur
plant
units
and
(
2)
other
sources
not
distinctly
listed.
Based
on
an
EPA
review
of
information
on
petroleum
refineries
during
development
of
the
proposed
standards,
it
was
determined
that
some
of
the
emissions
points
from
the
two
listed
categories
of
sources
have
similar
characteristics
and
can
be
controlled
by
the
same
control
techniques.
EPA
determined
that
it
is
most
effective
to
regulate
these
emission
points
in
a
single
regulation.

Data
analyses
conducted
in
developing
the
MACT
floor
for
miscellaneous
process
vents
determined
that
controls
can
achieve
98
percent
organic
HAP
reduction
or
an
outlet
organic
HAP
concentration
of
20
ppmv
or
less
for
all
vent
streams.
The
storage
vessel
provision
specifies
the
control
systems
which
represent
the
MACT
floor
to
be
applied
to
storage
vessels.
The
wastewater
provisions
of
this
rule
are
based
on
the
benzene
waste
operations
NESHAP
(
BWON),
which
controls
75
percent
of
the
benzene
in
refinery
wastewater.
The
wastewater
streams
subject
to
this
rule
include
water,
raw
material,
intermediate
product,

by­
product,
co­
product,
or
waste
material
that
contains
HAPs
and
ES­
4
is
discharged
into
an
individual
drain
system.
The
equipment
leak
provisions
of
the
promulgated
rule
are
based
on
the
Petroleum
Refinery
NSPS
Equipment
Leak
provisions,
as
well
as
the
negotiated
equipment
leak
regulation
included
in
the
Hazardous
Organics
NESHAP
(
HON)
(
40
CFR
63
subpart
H).

The
rule
specifies
the
necessary
recordkeeping
and
reporting
requirements
to
verify
compliance
with
the
MACT
floor
for
each
of
the
four
emission
points.
EPA
is
also
allowing
emission
averaging
among
existing
miscellaneous
process
vents,
storage
tanks,
and
wastewater
streams
within
a
refinery.
Under
emission
averaging,
a
system
of
emission
"
credits"
and
"
debits"
would
be
used
to
determine
whether
the
source
is
achieving
the
required
emission
reductions.
With
emissions
averaging
as
part
of
the
standard,
the
rule
contains
specific
equations
and
procedures
for
calculating
credits
and
debits.

ES.
3
NEED
FOR
REGULATION
One
of
the
concerns
about
potential
threats
to
human
health
and
the
environment
from
petroleum
refineries
is
the
emission
of
HAPs.
Health
risks
from
emissions
of
HAPs
into
the
air
include
increases
in
cancer
incidences
and
other
toxic
effects.
The
U.
S.

Office
of
Management
and
Budget
(
OMB)
directs
regulatory
agencies
to
demonstrate
the
need
for
an
economically
significant
rule.

The
RIA
must
show
that
a
market
failure
exists
and
that
it
cannot
be
resolved
by
measures
other
than
Federal
regulation.

Externality
is
one
type
of
market
failure.
HAP
emissions
represent
an
externality
in
that
refinery
operation
imposes
costs
on
others
outside
of
the
marketplace.
In
the
case
of
this
type
of
negative
externality,
the
market
price
of
goods
and
services
does
not
reflect
the
costs
borne
by
receptors
of
the
HAPs
generated
in
the
refining
process.
With
the
NESHAP
in
effect,

the
amount
that
refiners
must
incur
to
refine
petroleum
products
will
more
closely
approximate
the
full
social
costs
of
production.
The
necessity
for
a
uniform
national
standard
is
based
on
the
determination
that
air
pollution
crosses
jurisdictional
lines,
and
uniform
national
standards,
unlike
ES­
5
potentially
piecemeal
local
standards,
will
be
more
efficient
to
both
industry
and
government.

ES.
4
CONTROL
TECHNIQUES
AND
REGULATORY
ALTERNATIVES
The
promulgated
regulation
requires
a
broad
range
of
control
techniques
as
options
for
compliance
with
the
standard.

Combustion
technology,
internal
floating
roofs,
and
product
recovery
devices,
including
internal
floating
roofs
and
vapor
recovery
tanks,
are
all
part
of
the
technology
requirements
for
the
Petroleum
Refinery
NESHAP.
In
addition,
leak
detection
and
repair
(
LDAR)
programs
will
be
used
to
control
equipment
leaks.

Based
on
the
determination
of
the
MACT
floor
for
each
of
the
four
emission
points,
EPA
developed
a
single
regulatory
alternative.
It
is
a
hybrid
option,
that
incorporates
MACT
floor
level
control
for
wastewater
collection
and
treatment
systems,

storage
vessels,
and
miscellaneous
process
vents,
and
an
option
above
the
floor
for
equipment
leaks.
Cost
and
emission
data
were
unavailable
to
compare
this
alternative
with
a
second
alternative
to
examine
the
incremental
costs
and
benefits
of
going
to
another
alternative.

ES.
5
COST
ANALYSIS
The
annualized
compliance
costs
by
emission
point
are
shown
in
Table
ES­
1
for
the
chosen
alternative.
The
total
national
cost
of
Alternative
1
in
the
fifth
year
is
$
79
million.
TABLE
ES­
1.
SUMMARY
OF
TOTAL
COSTS
IN
THE
FIFTH
YEAR
FOR
THE
PETROLEUM
REFINING
INDUSTRY
REGULATION
Capital
Costs
and
Annual
Fifth
Year
Costs
(
1000$/
yr)
4
(
1992
Dollars)

Emission
Point
Option
Total
Capital
Costs
Existing
Sources
New
Construction
Total
Alternative
1
Equipment
Leaks
Miscellaneous
Process
Vents
Wastewater
Systems
Storage
Vessels
Other
Recordkeeping
and
Reporting
Floor
Option
11
Floor3
Floor1
Floor1
$
142,000
$
21,000
$
0
$
48,000
$
2,000
$
69,000
$
58,000
$
12,000
$
0
$
8,000
$
0
$(
210)

$
370
$
0
$
98
$
69,000
$
57,790
$
12,370
$
0
$
8,098
$
57,790
$
12,370
$
0
$
8,098
$
1,000
TOTAL
COST
$
213,000
$
79,190
NOTES:
1Alternative
1.
ES­
7
In
addition
to
provisions
for
the
installation
of
control
equipment,
the
promulgated
regulation
includes
provisions
for
monitoring,
recordkeeping,
and
reporting
(
MRR).
EPA
estimates
that
the
total
annual
cost
for
refineries
to
comply
with
the
MRR
requirements
is
$
20
million.
The
MRR
requirements
are
outlined
separately
in
the
promulgated
regulation
for
each
emission
point.

ES.
6
ECONOMIC
IMPACTS
AND
SOCIAL
COSTS
An
economic
impact
analysis
(
EIA)
was
conducted
to
evaluate
the
effect
of
increased
compliance
costs
for
emission
control
equipment
on
the
domestic
petroleum
refining
market.
The
partial
equilibrium
model
used
in
the
EIA
utilized
the
costs
for
Alternative
1
which
were
presented
in
Table
ES­
1
to
estimate
primary
market
impacts
including
increases
in
price
of
refined
petroleum
products,
decreases
in
output
levels,
changes
in
the
value
of
domestic
shipments,
and
possible
refinery
closures.

Estimated
secondary
effects
include
labor
market
adjustments,

energy
input
market
changes,
and
foreign
trade
effects.
Welfare
changes
for
consumers,
producers,
and
society
at
large
or
the
social
costs
of
the
emission
controls
were
also
evaluated.
The
estimated
market
changes
from
the
use
of
these
emission
controls
were
relatively
small.

The
social
costs
of
regulation
incorporate
costs
borne
by
society
for
pollution
abatement.
The
social
costs
reflect
the
opportunity
cost
or
economic
cost
of
resources
used
in
emission
control.
Consumers,
producers,
and
all
of
society
bear
the
costs
of
pollution
controls
in
the
form
of
higher
prices,
lower
quantities
produced,
and
possible
tax
revenues
that
may
be
gained
or
lost.
The
annual
social
cost
estimates
for
the
chosen
is
shown
in
Table
ES­
2.
The
social
costs
are
used
later
in
the
RIA
to
conduct
a
benefit
cost
analysis.
ES­
8
TABLE
ES­
2.
ANNUAL
SOCIAL
COST
ESTIMATES
FOR
THE
PETROLEUM
REFINING
REGULATION
(
Millions
of
1992
dollars)

Social
Cost
Category
Net
Costs1
Surplus
Losses
for
Preferred
Alternative:
Change
in
Consumer
Surplus
Change
in
Producer
Surplus
Change
in
Residual
Surplus
to
Society2
$
342.86
$(
174.32)
$(
73.25)

Total
Social
Cost
of
Alternative
13
$
95.29
NOTES:
1Brackets
indicate
negative
surplus
losses
or
surplus
gains.
2Residual
surplus
loss
to
society
includes
adjustments
necessary
to
equate
the
relevant
discount
rate
to
the
social
cost
of
capital
and
to
consider
appropriate
tax
effect
adjustments.
3Alternative
1
includes
floor
controls
for
all
emission
points
except
equipment
leaks.
Option
1
is
preferred
to
the
floor
for
equipment
leaks
because
it
is
a
less
costly
option
than
the
floor.
The
social
costs
was
calculated
by
reducing
the
social
costs
for
the
chosen
alternative
(
Alternative
1)
at
proposal
minus
the
reduction
in
annual
engineering
cost
estimates
between
proposal
and
promulgation,
and
assuming
the
same
percentage
change
in
the
social
costs.
ES­
9
ES.
7
QUALITATIVE
ASSESSMENT
OF
BENEFITS
OF
EMISSION
REDUCTIONS
This
RIA
presents
the
results
of
an
examination
of
the
potential
health
and
welfare
benefits
associated
with
air
emission
reductions
projected
as
a
result
of
implementation
of
the
petroleum
refinery
NESHAP.
The
promulgated
regulation
is
expected
to
reduce
emissions
of
HAPs
emitted
from
storage
tanks,

process
vents,
equipment
leaks,
and
wastewater
emission
points
at
refining
sites.
Of
the
HAPs
emitted
by
petroleum
refineries,

some
are
classified
as
VOCs,
which
are
ozone
precursors.
HAP
benefits
are
presented
separately
from
the
benefits
associated
specifically
with
VOC
emission
reductions.

The
predicted
emissions
of
a
few
HAPs
associated
with
this
regulation
have
been
classified
as
probable
or
known
human
carcinogens.
As
a
result,
one
of
the
benefits
of
the
proposed
regulation
is
a
reduction
in
the
risk
of
cancer
mortality.
Other
benefit
categories
include
reduced
exposure
to
noncarcinogenic
HAPs,
and
reduced
exposure
to
VOCs.

Emissions
of
VOCs
have
been
associated
with
a
variety
of
health
and
welfare
impacts.
VOC
emissions,
together
with
NO
x,

are
precursors
to
the
formation
of
tropospheric
ozone.
Exposure
to
ambient
ozone
is
most
directly
responsible
for
a
series
of
respiratory
related
adverse
impacts.

ES.
8
QUANTITATIVE
ASSESSMENT
OF
BENEFITS
Based
on
existing
data,
the
benefits
associated
with
reduced
HAP
and
VOC
emissions
were
quantified.
The
quantification
of
dollar
benefits
for
all
benefit
categories
is
not
possible
at
this
time
because
of
limitations
in
both
data
and
available
methodologies.
Although
an
estimate
of
the
total
reduction
in
HAP
emissions
for
various
control
options
has
been
developed
for
this
RIA,
it
has
not
been
possible
to
identify
the
speciation
of
the
HAP
emission
reductions
for
each
type
of
emission
point.

However,
an
estimate
of
HAP
speciation
for
equipment
leaks
has
been
made.
Using
emissions
data
for
equipment
leaks
and
the
ES­
10
Human
Exposure
Model
(
HEM),
the
annual
cancer
risk
caused
by
HAP
emissions
from
petroleum
refineries
was
estimated.
Generally,

this
benefit
category
is
calculated
as
the
difference
in
estimated
annual
cancer
incidence
before
and
after
implementation
of
each
regulatory
alternative.
Since
the
annual
cancer
incidence
associated
with
baseline
conditions
was
less
than
one
life
per
year,
the
benefits
associated
with
the
petroleum
refinery
NESHAP
were
determined
to
be
small.
Therefore,
these
benefits
are
not
incorporated
into
this
benefit
analysis.

The
benefits
of
reduced
emissions
of
VOC
from
a
MACT
regulation
of
petroleum
refineries
were
quantified
using
the
technique
of
"
benefits
transfer."
Because
there
is
an
assumption
incorporated
into
a
report
completed
by
the
Office
of
Technology
Assessment
(
OTA)
from
which
benefits
transfer
values
were
obtained
that
no
health
benefits
are
experienced
in
attainment
areas,
the
VOC
emission
reductions
used
in
this
analysis
are
defined
in
terms
of
reductions
occurring
only
in
non­
attainment
areas.
(
Nonattainment
areas
are
geographical
locations
in
which
the
Federal
ambient
air
quality
standard
(
NAAQS)
for
ozone
has
been
violated.)
Table
ES­
3
presents
the
VOC
emission
reductions
for
refineries
in
nonattainment
and
attainment
areas
associated
with
each
alternative.

The
benefit
transfer
ratio
range
for
acute
health
impacts
used
in
this
analysis
is
presented
in
Table
ES­
4.
In
order
to
quantify
VOC
emission
reductions,
these
ratios
were
multiplied
by
VOC
emission
reductions
from
petroleum
refineries
located
in
ozone
non­
attainment
areas.
Estimated
benefits
for
VOC
reductions
are
$
108.5
million
for
the
chosen
alternative.

TABLE
ES­
3.
VOC
EMISSION
REDUCTIONS
BY
EMISSION
POINT
ES­
11
VOC
Emission
Reductions
by
Regulatory
Alternative
(
Mg/
yr)
3
Alternative
1
Alternative
2
Emission
Point2
Nonattainme
nt1
Attainm
ent
Nonattainme
nt1
Attainme
nt
Equipment
Leaks
56,601
69,052
59,587
71,059
Miscellaneous
Process
Vents
76,426
47,438
76,426
47,438
Storage
Vessels
2,256
1,227
4,421
2,155
TOTAL
REDUCTION
BY
ATTAINMENT
STATUS
134,283
117,717
140,434
120,651
TOTAL
REDUCTION
BY
ALTERNATIVE
252,000
261,085
1VOC
emission
reductions
include
only
those
associated
with
control
of
the
87
refineries
located
in
ozone
nonattainment
areas.
2No
further
control
is
assumed
for
wastewater
streams,
and
therefore,
emission
reductions
associated
with
this
emission
point
is
zero.
3Emission
reduction
estimates
do
not
incorporate
reductions
occurring
at
new
sources.

TABLE
ES­
4.
BENEFIT
PER
MEGAGRAM
VALUES
FOR
VOC
REDUCTIONS
Benefits
Transfer
Value1
1992
Dollars/
Megagram2
Average
$
800
Range
$
25
­
$
1,574
1The
benefits
transfer
value
in
the
table
quantifies
only
the
benefits
attributable
to
acute
health
impacts.

2Values
are
in
first
quarter
1992
dollars.

ES.
9
COMPARISON
OF
BENEFITS
TO
COSTS
ES­
12
Table
ES­
5
depicts
a
comparison
of
the
benefits
of
implementing
the
chosen
regulatory
alternative
only
to
the
compliance
and
social
costs.
Data
for
calculating
the
benefits
for
a
second
alternative
were
not
available,
thus
the
Agency
was
unable
to
examine
the
incremental
benefits
and
incremental
costs
of
going
to
a
second
alternative
and
determine
if
maximum
net
benefits
are
approached
with
the
chosen
alternative.
There
are
positive
net
benefits
from
control
at
the
chosen
alternative,

however.
The
benefits
to
society
are
$
14.5
million
annually
from
compliance
with
the
standard.
ES­
13
TABLE
ES­
5.
COMPARISON
OF
ANNUAL
BENEFITS
TO
COSTS
FOR
THE
NATIONAL
PETROLEUM
REFINING
INDUSTRY
REGULATION
(
MILLIONS
OF
1992
DOLLARS
PER
YEAR)

Alternativ
e
1
Benefits
$
108.48
Social
Costs
$(
95.29)

Benefits
Less
Social
Costs
$
13.19
(
)
represent
costs
or
negative
values.
ES­
14
1
1.0
INTRODUCTION
The
regulation
under
analysis
in
this
report,
which
is
being
promulgated
under
Section
112
of
the
Clean
Air
Act
Amendments
of
1990
(
CAA),
is
the
Petroleum
Refinery
National
Emission
Standard
for
Hazardous
Air
Pollutants
(
NESHAP).
This
emission
standard
would
regulate
the
emissions
of
certain
hazardous
air
pollutants
(
HAPs)
from
petroleum
refineries.
The
petroleum
refineries
industry
group
includes
any
facility
engaged
in
producing
motor
gasoline,
naphthas,
kerosene,
jet
fuels,
distillate
fuel
oils,

residual
fuel
oils,
lubricants,
or
other
products
made
from
crude
oil
or
unfinished
petroleum
derivatives.
This
report
analyzes
the
impact
that
regulatory
action
is
likely
to
have
on
the
petroleum
refining
industry,
and
on
society
as
a
whole.
Included
in
this
chapter
is
a
summary
of
the
purpose
of
this
regulatory
impact
analysis
(
RIA),
the
statutory
history
which
preceded
this
regulation,
and
a
description
of
the
content
of
this
report.

1.1
PURPOSE
The
President
issued
Executive
Order
12866
on
October
4,
1993.

It
requires
EPA
to
prepare
RIAs
for
all
"
significant"
regulatory
actions.
The
criteria
set
forth
in
Section
1
of
the
Order
for
determining
whether
a
regulation
is
a
significant
rule
are
that
the
rule:
(
1)
is
likely
to
have
an
annual
effect
on
the
economy
of
$
100
million
or
more,
or
adversely
and
materially
affect
a
sector
of
the
economy,
productivity,
competition,
jobs,
the
environment,
public
health
or
safety,
or
State,
local,
or
tribal
governments
or
communities;
(
2)
is
likely
to
create
a
serious
inconsistency
or
otherwise
interfere
with
an
action
taken
or
planned
by
another
agency;
(
3)
is
likely
to
materially
alter
the
2
budgetary
impact
of
entitlements,
grants,
user
fees,
or
loan
programs
or
the
rights
and
obligation
of
recipients
thereof;
or
(
4)
is
likely
to
raise
novel
legal
or
policy
issues
arising
out
of
legal
mandates,
the
President's
priorities,
or
the
principles
set
forth
in
the
Executive
Order.
EPA
has
determined
that
the
petroleum
refinery
NESHAP
is
a
"
significant"
rule
because
it
will
have
an
annual
effect
on
the
economy
of
more
than
$
100
million,

and
is
therefore
subject
to
the
requirements
of
Executive
Order
12866.

Along
with
requiring
an
assessment
of
benefits
and
costs,
E.
O.

12866
specifies
that
EPA,
to
the
extent
allowed
by
the
CAA
and
court
orders,
demonstrate
(
1)
that
the
benefits
of
the
NESHAP
regulation
will
outweigh
the
costs
and
(
2)
that
the
maximum
level
of
net
benefits
(
including
potential
economic,
environmental,

public
health
and
safety
and
other
advantages;
distributive
impacts;
and
equity)
will
be
reached.
EPA
has
chosen
two
regulatory
options
to
be
evaluated
in
this
RIA.
For
each
of
the
two
options,
benefits
and
costs
are
quantified
to
the
greatest
extent
allowed
by
available
data.
As
stipulated
in
E.
O.
12866,

in
deciding
whether
and
how
to
regulate,
EPA
is
required
to
assess
all
costs
and
benefits
of
available
regulatory
alternatives,
including
the
alternative
of
not
regulating.

Accordingly,
the
cost
benefit
analysis
in
this
report
is
measured
against
the
baseline,
which
represents
industry
conditions
in
the
absence
of
regulation.

1.2
LEGAL
HISTORY
AND
STATUTORY
AUTHORITY
The
petroleum
refinery
NESHAP
would
require
sources
to
achieve
emission
limits
reflecting
the
application
of
the
maximum
achievable
control
technology
(
MACT),
consistent
with
sections
112(
d)
and
112(
h)
of
the
CAA.
This
section
provides
a
brief
history
of
Section
112
of
the
Act
and
background
regarding
the
definition
of
source
categories
and
emission
points
for
Section
112
standards.

Section
112
of
the
Act
provides
a
list
of
189
HAPs
and
directs
the
EPA
to
develop
rules
to
control
HAP
emissions.
The
CAA
3
requires
that
the
rules
be
established
for
categories
of
sources
of
the
emissions,
rather
than
being
set
by
pollutant.
In
addition,
the
CAA
establishes
specific
criteria
for
establishing
a
minimum
level
of
control
and
criteria
to
be
considered
in
evaluating
control
options
more
stringent
than
the
minimum
control
level.
Assessment
and
control
of
any
remaining
unacceptable
health
or
environmental
risk
is
to
occur
8
years
after
the
rules
are
promulgated.

For
the
subject
NESHAP,
EPA
chose
regulatory
options
based
on
control
options
on
an
emission
point
basis.
The
petroleum
refinery
NESHAP
regulates
emissions
of
all
HAPs
emitted
from
all
emission
points
at
both
new
and
existing
petroleum
refinery
sources.
An
emission
point
is
defined
as
a
point
within
a
refinery
which
emits
one
or
more
HAPs.
The
emission
points
to
be
regulated
under
the
source
category
for
this
standard
are:

equipment
leaks,
storage
vessels,
miscellaneous
process
vents,

and
wastewater
collection
and
treatment
systems.

1.3
REPORT
ORGANIZATION
Chapter
2
presents
a
summary
of
the
promulgated
regulation
for
the
Petroleum
Refinery
NESHAP.
Executive
Order
12866
requires
EPA
to
prove
that
regulation
is
necessary
due
to
a
compelling
public
need,
such
as
material
failures
of
private
markets
to
protect
or
improve
the
health
and
safety
of
the
public,
the
environment,
or
the
well­
being
of
the
public.
In
order
to
satisfy
this
requirement,
Chapter
3
presents
the
market
conditions
which
necessitate
regulatory
action.
A
characterization
of
the
air
emissions
associated
with
the
petroleum
refining
process,
and
the
significance
of
the
environmental
problem
which
EPA
intends
to
address
through
regulation
are
assessed.
An
explanation
of
how
the
regulation
is
consistent
with
the
CAA
is
also
presented.

Chapter
4
identifies
the
control
techniques
and
regulatory
alternatives
which
were
considered
for
the
standard.
EPA's
designation
of
control
options
reflects
the
best
control
technology
available
to
refineries,
given
existing
technology
4
levels.
Chapter
5
presents
the
approach
for
estimating
regulatory
compliance
costs,
the
quantitative
estimates
of
each
control
option
under
analysis,
and
the
issues
and
assumptions
upon
which
the
estimates
were
based.
The
associated
emission
reductions
and
cost
effectiveness
of
the
regulatory
options
are
also
presented.

Chapter
6
provides
an
economic
profile
of
the
petroleum
refining
industry,
and
describes
the
methodology
used
to
estimate
the
economic
effects
of
a
chosen
hybrid
option
on
the
industry.

Predicted
price,
output,
employment,
and
closure
impacts
are
presented
as
well
as
a
quantification
of
the
social
costs
of
the
regulatory
option.

Chapter
7
provides
a
qualitative
description
of
the
benefits
associated
with
the
regulatory
action.
As
explained
in
this
chapter,
some
benefits
are
nonquantifiable
and
therefore
cannot
be
usefully
estimated.
Qualitative
measures
of
the
air
related
benefits
associated
with
a
decrease
in
HAP
emissions
are
presented
separately
from
those
associated
with
a
decrease
in
volatile
organic
compound
(
VOC)
emissions.
Benefits
which
are
difficult
to
quantify,
but
nevertheless
essential
to
consider,

are
also
identified
in
this
chapter.

Chapter
8
provides
a
quantitative
assessment
of
those
benefits
which
were
identified
in
Chapter
7.
The
methodology
used
to
arrive
at
these
estimates
is
outlined
and
any
limitations
are
identified.
The
quantitative
estimates
of
benefits
associated
with
risk
reductions
and
human
health
effects
are
presented
separately.

Executive
Order
12866
requires
EPA
to
assess
both
the
costs
and
the
benefits
of
the
intended
regulation
and,
recognizing
that
some
costs
and
benefits
are
difficult
to
quantify,
adopt
a
regulation
only
on
a
determination
that
the
benefits
of
the
regulation
justify
the
costs.
Chapter
9
compares
the
annualized
costs
to
the
annualized
benefits
for
each
of
the
two
regulatory
options
in
this
RIA.
Economic
efficiency
is
considered
within
the
context
of
a
welfare
analysis,
using
the
social
costs
of
regulation.
5
2.0
PROMULGATED
PETROLEUM
REFINERIES
EMISSION
STANDARD
IN
BRIEF
The
discussion
in
this
chapter
briefly
summarizes
the
requirements
of
the
rule,
without
accounting
for
how
the
provisions
were
selected
or
how
emission
cutoffs
were
determined.

The
promulgated
rule,
the
NESHAP
for
petroleum
refineries,
would
require
sources
to
achieve
emission
limits
reflecting
the
application
of
MACT,
consistent
with
sections
112(
d)
and
112(
h)

of
the
CAA.
The
promulgated
rule
would
regulate
the
emissions
of
the
organic
HAPs
identified
on
the
list
of
189
HAPs
in
the
CAA
at
both
new
and
existing
petroleum
refinery
sources.

The
final
standard
defines
source
as
the
collection
of
emission
points
in
HAP­
emitting
petroleum
refining
processes
within
the
source
category.
The
source
comprises
all
miscellaneous
process
vents,
storage
vessels,
wastewater
streams,

and
equipment
leaks
associated
with
petroleum
refining
process
units
that
are
located
at
a
single
plant
site
covering
a
contiguous
area
under
common
control.
The
definition
of
source
is
an
important
element
of
this
NESHAP
because
it
describes
the
specific
grouping
of
emission
points
within
the
source
category
to
which
each
standard
applies.

2.1
THE
EMISSION
STANDARD
IN
BRIEF
The
rule
is
made
up
of
seven
different
subjects:

applicability,
definitions,
and
general
standards;
miscellaneous
process
vent
provisions;
storage
vessel
provisions;
wastewater
provisions;
equipment
leak
provisions;
recordkeeping
and
reporting
provisions;
and
emissions
averaging.
Each
of
these
sections
is
summarized
below.
6
2.1.1
Applicability
of
the
Petroleum
Refinery
NESHAP
The
applicability
of
the
rule
refers
to
the
definition
of
the
source
within
the
petroleum
refinery
source
category.
Petroleum
refineries
are
defined
as
facilities
engaged
in
producing
motor
gasoline,
naphthas,
kerosene,
jet
fuels,
distillate
fuel
oils,

residual
fuel
oils,
or
other
transportation
fuels,
heating
fuels,

or
lubricants
from
crude
oil
or
unfinished
petroleum
derivatives.

The
emission
standard
applies
to
petroleum
refining
process
units
that
are
part
of
a
major
source
as
defined
in
Section
112
of
the
CAA.
EPA's
initial
source
category
list
(
57
FR
31576,

July
16,
1992),
required
by
section
112(
c)
of
the
Act,
identifies
categories
of
sources
for
which
NESHAP
are
to
be
established.

This
list
includes
all
categories
of
major
sources
of
HAPs
known
to
the
EPA
at
this
time,
and
all
area
source
categories
for
which
findings
of
adverse
effects
warranting
regulation
have
been
made.

Two
categories
of
sources
are
listed
in
the
initial
source
category
list
for
petroleum
refineries:
(
1)
catalytic
cracking
(
fluid
and
other)
units,
catalytic
reforming
units,
and
sulfur
plant
units
and
(
2)
other
sources
not
distinctly
listed.

Based
on
an
EPA
review
of
information
on
petroleum
refineries
during
development
of
the
promulgated
standards,
it
was
determined
that
some
of
the
emissions
points
from
the
two
listed
categories
of
sources
have
similar
characteristics
and
can
be
controlled
by
the
same
control
techniques.
In
particular,

miscellaneous
process
vents
emitting
organic
HAPs,
storage
vessels,
wastewater
streams,
and
leaks
from
equipment
in
organic
HAP
service
within
catalytic
cracking
units,
catalytic
reforming
units,
and
sulfur
plant
units
are
similar
to
emission
points
from
the
other
process
units
at
petroleum
refineries.
EPA
determined
that
it
is
most
effective
to
regulate
these
emission
points
in
a
single
regulation,
and
all
emission
points
regulated
by
the
subject
NESHAP
are
in
a
single
source
category.

2.1.2
Miscellaneous
Process
Vent
Provisions
Miscellaneous
process
vents
include
vents
from
petroleum
refining
process
units
that
emit
organic
HAP's.
Vents
that
are
7
routed
to
the
refinery
fuel
gas
system
are
considered
to
be
part
of
the
process
and
are
not
subject
to
the
standard.
The
miscellaneous
process
vent
provisions
define
two
groups
of
vents.

Group
1
process
vents
are
those
with
VOC
emissions
greater
than
or
equal
to
33
kilograms
per
day
(
kg/
day)
(
72
lbs/
day).
Group
2
vents
are
vents
with
emissions
below
this
level.

The
miscellaneous
process
vent
provisions
for
new
and
existing
sources
require
the
owner
or
operator
of
a
Group
1
miscellaneous
process
vent
to
reduce
organic
HAP
emissions
by
98
percent
or
to
less
than
20
parts
per
million
by
volume
(
ppmv),
or
to
reduce
emissions
using
a
flare
meeting
the
requirements
of
section
63.11(
b)
of
the
NESHAP
General
Provisions
(
40
CFR
part
63
subpart
A).

Monitoring
requirements
for
Group
1
vents
include
an
initial
performance
demonstration
and
monitoring
of
control
device
operating
parameters.
The
owner
could
also
comply
by
reducing
emissions
from
a
Group
1
process
vent
to
less
than
33
kg/
day
(
72
lbs/
day),
thereby
converting
it
to
a
Group
2
process
vent.
No
controls
or
monitoring
are
required
for
Group
2
process
vents.

The
process
vent
provisions
are
the
same
for
both
new
and
existing
petroleum
refinery
sources.

2.1.3
Storage
Vessel
Provisions
The
storage
vessel
provisions
define
two
groups
of
vessels:

Group
1
vessels
are
vessels
with
a
design
storage
capacity
and
a
maximum
true
vapor
pressure
above
the
values
specified
in
the
regulation.
Group
2
vessels
are
all
storage
vessels
that
are
not
Group
1
vessels.
The
storage
provisions
require
that
one
of
the
following
control
systems
be
applied
to
Group
1
storage
vessels:

(
1)
An
internal
floating
roof
(
IFR)
with
proper
seals;
(
2)
an
external
floating
roof
(
EFR)
with
proper
seals;
(
3)
an
EFR
converted
to
an
IFR
with
proper
seals;
or
(
4)
a
closed
vent
system
with
a
95
percent
efficient
control
device.
The
storage
provisions
give
details
on
the
type
of
seals
required.

Monitoring
and
compliance
provisions
for
Group
1
vessels
include
periodic
external
visual
inspections
of
vessels
and
roof
seals,
8
as
well
as
less
frequent
internal
inspections.
If
a
closed
vent
system
and
control
device
is
used
for
venting
emissions
from
Group
1
storage
vessels,
the
owner
or
operator
must
establish
appropriate
monitoring
procedures.
No
controls
or
inspections
are
required
for
Group
2
storage
vessels.

For
existing
sources,
the
final
rule
requires
that
fixed
roof
tanks
with
capacities
greater
than
or
equal
to
177
cubic
meters
(
m3)
(
1,115
barrels
or
47,000
gallons)
that
store
liquids
with
vapor
pressures
greater
than
10.2
kilopascals
(
kPa)
(
1.5
pounds
per
square
inch
absolute
(
psia))
comply
fully
with
the
rule
within
3
years.
Owners
or
operators
of
IFR
or
EFR
tanks
are
allowed
to
defer
upgrading
of
their
seals
to
meet
the
NESHAP
requirements
until
the
next
scheduled
inspection
and
maintenance
activity
or
within
10
years,
whichever
comes
first.
For
new
sources,
the
final
rule
requires
that
vessels
with
capacities
greater
than
or
equal
to
151
m3
(
950
barrels
or
40,000
gallons),

with
vapor
pressures
equal
to
or
greater
than
3.4
kPa
(
0.5
psia),

and
vessels
with
capacities
equal
to
or
greater
than
76
m3
(
475
barrels
or
20,000
gallons)
storing
liquids
with
vapor
pressures
equal
to
or
greater
than
77
kPa
(
11.1
psia)
comply
with
the
level
of
control
required
by
40
CFR
part
63
subpart
G
(
including
the
controlled
fitting
requirements).

2.1.4
Wastewater
Provisions
The
wastewater
provisions
of
this
rule
are
based
on
the
benzene
waste
operations
NESHAP
(
BWON),
using
benzene
as
a
surrogate
for
all
HAPs
from
wastewater
in
petroleum
refineries.

EPA
research
concluded
that
benzene
is
a
good
indicator
of
the
presence
of
other
HAPs.
The
wastewater
streams
subject
to
this
rule
include
water,
raw
material,
intermediate
product,

by­
product,
co­
product,
or
waste
material
that
contains
HAPs
and
is
discharged
into
an
individual
drain
system.
The
wastewater
provisions
define
two
groups
of
wastewater
streams.
Group
1
streams
are
those
that
are
located
at
a
refinery
with
a
total
annual
benzene
loading
of
at
least
10
megagrams
per
year
and
are
not
exempt
from
control
requirements
under
40
CFR
61
subpart
FF
9
(
the
BWON).
In
general,
streams
are
not
exempt
from
40
CFR
part
61
subpart
FF
if
they
contain
a
concentration
of
at
least
10
parts
per
million
by
weight
(
ppmw)
benzene,
and
have
a
flow
rate
of
at
least
0.02
liters
per
minute
(
l/
min)
(
0.005
gallons
per
minutes
(
gal/
min)).
Group
2
streams
are
wastewater
streams
that
are
not
Group
1.

The
wastewater
provisions
of
the
final
rule
refer
to
the
BWON
for
both
new
and
existing
sources,
which
requires
owners
or
operators
of
a
Group
1
wastewater
stream
to
reduce
benzene
mass
by
99
percent
using
suppression
followed
by
steam
stripping,

biotreatment,
or
other
treatment
processes.
Vents
from
stream
strippers
and
other
waste
management
or
treatment
units
are
required
to
be
controlled
by
a
control
device
achieving
95
percent
emissions
reduction
or
20
ppmv
at
the
outlet
of
the
control
device.
The
performance
tests,
monitoring,
reporting,

and
recordkeeping
provisions
required
to
demonstrate
compliance
are
included
in
the
BWON.
No
controls
or
monitoring
are
required
for
Group
2
wastewater
streams.

2.1.5
Equipment
Leak
Provisions
The
equipment
leak
standards
for
the
petroleum
refinery
NESHAP
allow
owners
and
operators
of
existing
sources
to
choose
between
complying
with
equipment
leaks
provisions
in
40
CFR
part
60
subpart
VV
(
Petroleum
Refinery
NSPS
Equipment
Leaks
Standard)
or
complying
with
a
modified
negotiatied
regulation
for
equipment
leaks
presented
in
40
CFR
part
63
subpart
H
(
HON
equipment
leaks).
The
differences
in
the
refinery
equipment
leak
requirements
and
the
HON
equipment
leak
provisions
are
in
the
leak
definitions
and
connector
monitoring
provisions.

Under
either
of
the
two
options,
existing
refineries
subject
to
the
rule
will
be
required
to
implement
a
Leak
Detection
and
Repair
(
LDAR)
program
with
the
same
leak
definitions
(
10,000
ppm)

and
frequencies
as
specified
in
40
CFR
part
60
subpart
VV
within
3
years
after
promulgation
of
the
petroleum
refineries
NESHAP.

Refineries
that
choose
to
comply
with
the
modified
negotiated
regulation
would
implement
the
Phase
II
leak
definitions
and
frequencies
at
the
end
of
the
fourth
year
after
promulgation,
and
comply
with
Phase
III
requirements
5
1/
2
years
after
10
promulgation.
Phase
III
has
lower
leak
definitions,
but
allows
less
frequent
monitoring
for
good
performers.
Although
the
modified
negotiated
regulation
is
not
required
in
the
final
rule,

the
EPA
believes
that
it
would
provide
greater
emission
reductions
and,
in
many
cases,
would
be
more
cost
effective
than
40
CFR
part
60
subpart
VV
and
could
even
provide
cost
savings.

Cost
savings
would
occur
because
it
would
reduce
equipment
leak
product
loss,
and
facilities
with
a
low
percent
of
leaking
valves
would
be
able
to
monitor
less
frequently,
thereby
reducing
monitoring
costs.

New
sources
must
comply
at
startup
with
the
modified
negotiated
regulation;
pumps
and
valves
at
new
sources
must
be
in
compliance
with
the
Phase
II
requirements
at
startup
rather
than
Phase
I.
This
is
consistent
with
the
negotiated
rule
(
40
CFR
part
63
subpart
H).

2.1.6
Marine
Vessel
Loading
and
Unloading,
Bulk
Gasoline
Terminal
or
Pipeline
Breakout
Station
Storage
Vessels,
and
Bulk
Gasoline
Terminal
Loading
Rack
Provisions
The
final
refineries
NESHAP
requires
marine
vessel
loading
and
unloading
operations
at
refineries
to
comply
with
the
marine
loading
NESHAP
(
40
CFR
part
63
subpart
Y)
unless
they
are
included
in
an
emissions
average.
Bulk
gasoline
terminal
or
pipeline
breakout
station
storage
vessel
and
equipment
leaks,
and
bulk
gasoline
terminal
loading
racks
at
refineries
are
required
to
comply
with
the
gasoline
distribution
NESHAP
(
40
CFR
part
63
subpart
R)
unless
they
are
included
in
an
emissions
average
(
equipment
leaks
cannot
be
included
in
an
emissions
average).

2.1.7
Recordkeeping
and
Reporting
Provisions
The
final
rule
requires
petroleum
refineries
subject
to
40
CFR
part
63
subpart
CC
maintain
required
records
for
a
period
of
at
least
5
years.
The
final
rule
required
that
the
following
three
types
of
reports
be
submitted:
(
1)
a
Notification
of
Compliance
Status,
(
2)
periodic
reports,
and
(
3)
other
reports.
11
2.1.7
Emission
Averaging
The
EPA
is
allowing
emission
averaging
among
existing
miscellaneous
process
vents,
refining
storage
vessels,
and
wastewater
streams,
marine
vessel
loading
and
unloading
operations,
bulk
gasoline
terminals
or
pipeline
breakout
station
storage
vessels
and
bulk
gasoline
terminal
loading
racks
within
a
refinery.
New
sources
are
not
allowed
to
use
emissions
averaging.
Under
emission
averaging,
a
system
of
emission
"
credits"
and
"
debits"
would
be
used
to
determine
whether
the
source
is
achieving
the
required
emission
reductions.
12
13
3.0
NEED
FOR
REGULATION
One
of
the
concerns
about
potential
threats
to
human
health
and
the
environment
from
petroleum
refineries
is
the
emission
of
HAPs.
Health
risks
from
emissions
of
HAPs
into
the
air
include
increases
in
cancer
incidences
and
other
toxic
effects.
This
chapter
discusses
the
need
for
and
consequences
of
regulating
of
HAP
emissions
from
petroleum
refineries.

Section
3.1
presents
the
conditions
of
market
failure
which
necessitate
government
intervention.
Section
3.2
identifies
the
insufficiency
of
political
and
judicial
forces
to
control
the
release
of
toxic
air
pollutants
from
petroleum
refineries.

Section
3.3
provides
a
characterization
of
the
HAP
and
VOC
emissions
from
petroleum
refineries.
These
values
represent
the
baseline
against
which
the
emission
reductions
associated
with
the
regulatory
options
will
be
compared
in
the
cost
effectiveness
calculations
presented
in
Chapter
5
of
this
report.
Section
3.3
also
provides
more
detail
on
the
health
risks
of
these
pollutants.
Lastly,
Section
3.4
identifies
the
consequences
of
regulating
versus
the
option
of
not
regulating.

3.1
MARKET
FAILURE
The
U.
S.
Office
of
Management
and
Budget
(
OMB)
directs
regulatory
agencies
to
demonstrate
the
need
for
a
major
rule.
1
The
RIA
must
show
that
a
market
failure
exists
and
that
it
cannot
be
resolved
by
measures
other
than
Federal
regulation.
Market
failures
are
categorized
by
OMB
as
externalities,
natural
monopolies,
or
inadequate
information.
The
following
paragraphs
address
the
three
categories
of
market
failure.
14
3.1.1
Air
Pollution
as
an
Externality
Air
pollution
is
an
example
of
a
negative
externality.
This
means
that,
in
the
absence
of
government
regulation,
the
decisions
of
generators
of
air
pollution
do
not
fully
reflect
the
costs
associated
with
that
pollution.
For
a
petroleum
refiner,

air
pollution
from
the
refinery
is
a
product
or
by­
product
that
can
be
disposed
of
cheaply
by
venting
it
to
the
atmosphere.
Left
to
their
own
devices,
many
refiners
treat
air
as
a
free
good
and
do
not
fully
"
internalize"
the
damage
caused
by
emissions.
This
damage
is
born
by
society,
and
the
receptors

the
people
who
are
adversely
affected
by
the
pollution

are
not
able
to
collect
compensation
to
offset
their
costs.
They
cannot
collect
compensation
because
the
adverse
effects,
like
increased
risks
of
morbidity
and
mortality,
are
non­
market
goods,
that
is,
goods
that
are
not
explicitly
and
routinely
traded
in
organized
free
markets.

HAP
emissions
represent
an
externality
in
that
refinery
operation
imposes
costs
on
others
outside
of
the
marketplace.
In
the
case
of
this
type
of
negative
externality,
the
market
price
of
goods
and
services
does
not
reflect
the
costs,
borne
by
receptors
of
the
HAPs,
generated
in
the
refining
process.

Government
regulation
can
be
used
to
improve
the
situation.
For
example,
the
NESHAP
will
force
petroleum
refiners
to
reduce
the
quantity
of
HAPs
that
they
emit.
With
the
NESHAP
in
effect,
the
amount
that
refiners
must
incur
to
refine
petroleum
products
will
more
closely
approximate
the
full
social
costs
of
production.
In
the
long
run,
refiners
will
be
forced
to
increase
prices
of
the
petroleum
products
sold
in
order
to
cover
total
production
costs.

Thus,
prices
will
rise,
consumers
accordingly
will
reduce
their
demand
for
petroleum
products,
and
as
a
result,
fewer
petroleum
products
will
be
provided
to
the
market.
The
more
the
costs
of
pollution
are
internalized
by
the
petroleum
refiners,
the
greater
the
improvement
in
the
way
the
market
functions.

3.1.2
Natural
Monopoly
Natural
monopoly
exists
where
a
market
can
be
served
at
lowest
cost
only
if
production
is
limited
to
a
single
producer.
The
15
refining
industry
is
characterized
by
some
of
the
same
attributes
which
define
monopolistic
markets,
including
economies
of
scale,

and
barriers
to
entry
due
to
the
heavy
up­
front
capital
needed
for
refinery
construction.
Because
of
the
wide
diversity
in
the
size
and
number
of
petroleum
refineries,
however,
conditions
of
natural
monopoly
do
not
represent
a
market
failure
for
this
industry.

3.1.3
Inadequate
Information
The
third
category
of
potential
market
failure
that
sometimes
is
used
to
justify
government
regulation
is
inadequate
information.
Some
petroleum
refineries
can
reduce
costs
by
installing
air
pollution
control
devices,
or
reducing
leaks.
Due
to
lack
of
information,
some
of
these
refineries
do
not
install
such
systems.
The
NESHAP
will
require
the
collection
of
information
that
may
give
a
particular
petroleum
refiner
enough
data
to
make
an
informed
decision
on
whether
or
not
control
devices
are
the
best
option.

3.2
INSUFFICIENT
POLITICAL
AND
JUDICIAL
FORCES
There
are
a
variety
of
reasons
why
many
emission
sources,
in
EPA's
judgment,
should
be
subject
to
reasonably
uniform
national
standards.
The
principal
reasons
are:


Air
pollution
crosses
jurisdictional
lines.


The
people
who
breathe
the
air
pollution
travel
freely,

sometimes
coming
in
contact
with
air
pollution
outside
their
home
jurisdiction.


Harmful
effects
of
air
pollution
detract
from
the
nation's
health
and
welfare
regardless
of
whether
the
air
pollution
and
harmful
effects
are
localized.


Uniform
national
standards,
unlike
potentially
piecemeal
local
standards,
are
not
likely
to
create
artificial
16
incentives
or
artificial
disincentives
for
economic
development
in
any
particular
locality.


One
uniform
set
of
requirements
and
procedures
can
reduce
paperwork
and
frustration
for
firms
that
must
comply
with
emission
regulations
across
the
country.

3.3
ENVIRONMENTAL
FACTORS
WHICH
NECESSITATE
REGULATION
Regulation
of
the
petroleum
refining
industry
is
necessary
because
of
the
adverse
health
effects
caused
by
human
exposure
to
HAP
emissions.
This
section
characterizes
the
emissions
attributable
to
petroleum
refining
and
summarizes
the
adverse
health
effects
associated
with
human
exposure
to
HAP
emissions.

3.3.1
Air
Emission
Characterization
The
HAP
emissions
from
the
emission
points
that
comprise
the
source
in
this
source
category
are
all
organic
HAPs.
Therefore,

given
the
source
and
source
category
definitions,
the
provisions
of
this
NESHAP
apply
to
organic
HAPs
listed
in
section
112(
b)
of
the
CAA.
HAP
emissions
from
refineries
are
composed
of
a
few
chemicals,
including
benzene,
toluene,
xylenes,
ethylbenzene,
and
hexane.
There
is
a
narrower
range
of
variation
in
emission
stream
composition
among
petroleum
refinery
emission
points
than
there
is
in
some
other
source
categories
(
e.
g.,
Synthetic
Organic
Chemical
Manufacturing
Industry
(
SOCMI)
emission
points
regulated
by
the
HON).
However,
the
different
HAPs
emitted
have
different
toxicities,
and
there
are
some
variations
in
the
concentrations
of
individual
HAPs
and
the
emission
release
characteristics
of
different
emission
points.

Baseline
emissions
from
petroleum
refineries
were
estimated
using
information
published
in
the
Oil
and
Gas
Journal
(
OGJ)
and
provided
by
petroleum
refineries
in
response
to
information
collection
requests
and
questionnaires
sent
out
under
section
114
of
the
CAA.
Table
3­
1
presents
the
baseline
HAP
and
VOC
emissions
for
each
of
the
four
kinds
of
emission
points
controlled
by
this
promulgated
rule.
Emission
levels
of
other
air
pollutants
(
CO,
NO
x,
and
SO
2)
were
not
quantified.
Baseline
17
emissions
include
emissions
from
both
new
and
existing
sources.

Baseline
HAP
and
VOC
emissions
take
into
account
the
current
estimated
level
of
emissions
control,
based
on
questionnaire
responses
submitted
by
refineries,
and
on
related
regulations
which
have
already
been
promulgated.
(
These
regulations
are
summarized
later
in
this
chapter.)
As
a
result,
baseline
HAP
and
VOC
emissions
reflect
the
level
of
control
that
would
be
achieved
in
the
absence
of
the
promulgated
rule.

TABLE
3­
1.
NATIONAL
BASELINE
VOC
AND
HAP
EMISSIONS
BY
EMISSION
POINT
Baseline
Emissions
(
Mg/
yr)

Emission
Point
HAP
VOC
Miscellaneous
Process
Vents
10,000
109,000
Equipment
Leaks
52,000
189,000
Storage
Vessels
9,300
111,000
Wastewater
Collection
and
Treatment
10,000
10,000
TOTAL
81,300
419,000
Given
available
data,
it
has
not
been
possible
to
identify
individual
HAP
emissions
for
each
type
of
emission
point.

Speciated
HAP
emissions
were
available
only
for
equipment
leaks.

Since
HAP
emissions
from
equipment
leaks
account
for
nearly
65
percent
of
total
HAP
emissions
at
petroleum
refineries,
however,

this
speciation
is
valuable
for
approximating
the
minimum
level
of
cancer
risk
related
to
refinery
emissions.
Speciated
HAP
emissions
for
equipment
leaks
are
presented
in
Table
3­
2.

3.3.2
Harmful
Effects
of
HAPs
Exposure
to
HAPs
has
been
associated
with
a
variety
of
adverse
health
effects.
Direct
exposure
to
HAPs
can
occur
through
inhalation,
soil
ingestion,
the
food
chain,
and
dermal
contact.

Health
effects
associated
with
HAP
emissions
are
addressed
in
these
NESHAPs.
Many
HAPs
are
classified
as
known
human
carcinogens.
Other
HAPs
have
not
been
classified
as
known
human
carcinogens.
Exposure
to
these
pollutants,
however,
may
still
18
result
in
adverse
health
and
welfare
impacts
to
human
populations.

EPA
has
devised
a
system,
which
was
adapted
from
one
developed
by
the
International
Agency
for
Research
on
Cancer
(
IARC),
for
classifying
chemicals
based
on
the
weight­
of­
evidence.
2
Of
the
HAPs
listed
in
Table
3­
2,
only
benzene
is
classified
as
group
A,

or
a
known
human
carcinogen.
This
means
that
there
is
sufficient
evidence
to
support
that
the
chemical
causes
an
increased
risk
of
cancer
in
humans.
Benzene
is
a
concern
to
the
EPA
because
long
term
exposure
to
this
chemical
has
been
known
to
cause
leukemia
in
humans.
While
this
is
the
most
well
known
effect,
benzene
exposure
is
also
associated
with
aplastic
anemia,
multiple
myeloma,
lymphomas,
pancytopenia,
chromosomal
breakages,
and
weakening
of
bone
marrow
(
53
FR
28504;
July
28,
1988).

Cresols
is
considered
to
be
a
group
C
or
a
possible
human
carcinogen.
For
this
chemical,
there
is
either
inadequate
data
or
no
data
on
human
carcinogenicity,
and
there
is
limited
data
on
animal
carcinogenicity.
Therefore,
while
cancer
risk
is
possible,
there
is
not
sufficient
evidence
to
support
that
this
chemical
will
cause
increased
cancer
risks
in
humans.
The
remaining
HAPs
in
Table
3­
2
are
noncarcinogens.
19
TABLE
3­
2.
BASELINE
SPECIATED
HAP
EMISSIONS
FROM
EQUIPMENT
LEAKS
Hazardous
Air
Pollutant
Baseline
Emissions
(
Mg/
yr)

2,
2,
4­
Trimethylpentane
6,497
Benzene
2,190
Ethyl
Benzene
2,734
Hexane
6,309
Naphthalene
1,540
Toluene
9,256
Xylenes
8,737
Hydrogen
Fluoride
3,178
Phenol
1,429
Cresols
693
MTBE
6,716
Hydrogen
Chloride
229
Methyl
Ethyl
Ketone
2,435
TOTAL
51,943
20
uThough
they
do
not
cause
cancer,
they
are
considered
hazardous
because
of
the
other
significant
adverse
health
effects
with
which
they
are
associated.
These
other
adverse
health
effects
are
listed
in
Chapter
8
of
this
RIA.

Emissions
of
VOC
have
been
associated
with
a
variety
of
health
impacts.
VOCs,
together
with
NO
x,
are
precursors
to
the
formation
of
tropospheric
ozone.
It
is
exposure
to
ozone
that
is
responsible
for
adverse
respiratory
impacts,
including
coughing
and
difficulty
in
breathing.
Repeated
exposure
to
elevated
concentrations
of
ozone
over
long
periods
of
time
may
also
lead
to
chronic,
structural
damage
to
the
lungs.

3.4
CONSEQUENCES
OF
REGULATORY
ACTION
This
section
provides
an
assessment
of
the
consequences
of
the
attainment
of
EPA
emission
reduction
objectives,
and
the
likely
consequences
if
these
objectives
are
not
met.

3.4.1
Consequences
if
EPA's
Emission
Reduction
Objectives
are
Met
This
section
presents
the
environmental,
cost,
and
energy
use
impacts
resulting
from
the
control
of
HAP
emissions
under
the
promulgated
rule.
(
Economic
impacts
will
be
presented
in
Chapter
6.)
It
is
estimated
that
approximately
192
petroleum
refineries
would
be
required
to
apply
controls
by
the
proposed
standards.

Throughout
this
report,
impacts
are
presented
relative
to
the
baseline,
which
represents
the
level
of
control
in
the
absence
of
the
proposed
rule.
The
estimates
include
the
impacts
of
applying
control
to:
(
1)
existing
process
units
and
(
2)
additional
process
units
that
are
expected
to
begin
operation
over
a
5­
year
period.
Thus,
the
estimates
represent
annual
impacts
occurring
in
the
fifth
year.
Based
on
a
review
of
annual
construction
projects
over
the
years
1988
to
1992
listed
in
the
Oil
and
Gas
Journal,
it
was
assumed
that
34
new
process
units
would
be
constructed
each
year
over
a
5­
year
period.
21
3.4.1.1
Allocation
of
Resources.
There
will
be
improved
allocation
of
resources
associated
with
petroleum
refining.

Specifically,
more
of
the
costs
of
the
harmful
effects
of
the
refining
process
will
be
internalized
by
the
producers.
This,
in
turn,
will
affect
consumers'
purchasing
decisions.
To
the
extent
these
newly­
internalized
costs
are
then
passed
along
to
the
end
users
of
refined
petroleum
products,
and
to
the
extent
that
these
end
users
are
free
to
buy
as
much
or
as
little
of
the
petroleum
products
as
they
wish,
they
will
purchase
less
(
relative
to
their
purchases
of
other
competing
services).
If
this
same
process
of
internalizing
negative
externalities
occurs
throughout
the
entire
petroleum
refining
industry,
an
economically
optimal
situation
is
approached.
This
is
the
situation
in
which
the
marginal
cost
of
resources
devoted
to
petroleum
refining
equals
the
marginal
value
of
the
products
to
the
end
users
of
the
products.
Although
there
are
uncertainties
in
this
progression
of
impacts,
in
the
aggregate
and
in
the
long
run,
the
NESHAP
will
move
society
toward
this
economically
optimal
situation.

3.4.1.2
Emissions
Reductions.
The
environmental
impact
of
the
rule
includes
the
reduction
of
HAP
and
VOC
emissions.
Under
the
promulgated
rule,
it
is
estimated
that
the
emissions
of
HAP
from
refineries
would
be
reduced
by
48,000
Mg/
yr,
and
the
emissions
of
VOC
would
be
reduced
by
252,000
Mg/
yr.
Emission
levels
of
other
air
pollutants
(
CO,
NO
x,
and
SO
2)
were
not
quantified.
It
is
important
to
note
that
the
possibility
exists
for
slight
increases
above
existing
emission
levels
would
result
from
the
combustion
of
fossil
fuel
as
part
of
control
device
operations.
Additional
emissions
of
these
pollutants
would
be
attributable
to
the
additional
fuel
burned
to
generate
energy
for
operation
of
compressors
for
ducting
miscellaneous
process
vent
streams
to
control
devices.

3.4.1.3
Costs
and
Benefits.
The
cost
impact
of
the
rule
includes
the
capital
cost
of
new
control
equipment,
the
associated
operation
and
maintenance
cost,
and
the
cost
of
22
monitoring,
recordkeeping,
and
reporting.
Generally,
the
cost
impact
also
includes
any
cost
savings
generated
by
reducing
the
loss
of
valuable
product
in
the
form
of
emissions.
Under
the
promulgated
rule,
it
is
estimated
that
total
capital
costs
would
be
$
213
million
(
first
quarter
1992
dollars)
and
total
annual
costs
would
be
$
79
million
(
first
quarter
1992
dollars).

Table
3­
3
presents
the
capital
and
annual
cost
impact
of
the
regulation
for
each
of
the
four
emission
points
as
well
as
the
national
totals.

TABLE
3­
3.
NATIONAL
CONTROL
COST
IMPACTS
OF
PREFERRED
ALTERNATIVE
IN
THE
FIFTH
YEAR
Emission
Point
Total
Capital
Costs
(
Million
Dollars)
Total
Annual
Costs
(
Million
Dollars)

Miscellaneous
Process
Vents
21.0
12.0
Equipment
Leaks
142.0
58.0
Storage
Vessels
48.0
8.0
Wastewater
Collection
and
Treatment
Other
recordkeeping
and
reporting
b
2.0
b
1.0
TOTAL
213.0
79.0
NOTES:
bThe
MACT
level
of
control
is
no
additional
control.

3.4.1.4
Energy
Impacts.
Increases
in
energy
use
were
estimated
for
operating
control
equipment
that
would
be
required
by
the
promulgated
standards
(
compressors
for
ducting
miscellaneous
process
vent
streams
to
control
devices).
The
estimated
energy
use
increase
in
the
fifth
year
would
be
48
million
kw­
hr/
yr
of
electricity
or
77.5
thousand
barrels
of
oil
equivalent.
3
3.4.1.5
State
Regulation
and
New
Source
Review.
State
regulatory
programs
will
be
strengthened
since
there
is
now
a
more
stringent
and
comprehensive
federal
standard
they
can
use
as
their
basis
for
their
efforts.
Some
components
of
the
petroleum
refining
industry
have
already
been
subject
to
various
Federal,
23
State,
and
local
air
pollution
control
rules.
Although
these
existing
rules
will
remain
in
effect,
the
petroleum
refinery
NESHAP
will
provide
comprehensive
coverage
of
the
petroleum
refinery
sources
not
covered
by
the
existing
rules.
Recognition
that
the
NESHAP
is
effectively
reducing
emissions
will
expedite
the
State
process
of
reviewing
applications
for
new
petroleum
refineries
and
issuing
permits
for
their
construction
and
operation.
State
regulations
will
also
be
uniform,
and
the
disadvantages
of
the
piecemeal
approach
to
emission
regulation
will
be
avoided.

3.4.1.6
Other
Federal
Programs.
The
regulations
which
affect
the
petroleum
refining
industry
that
have
already
been
promulgated
include
a
number
of
NSPS,
(
40
CFR
60):
subpart
J

Standards
of
Performance
for
Petroleum
Refineries;
subparts
K,

Ka,
and
Kb

various
standards
of
performance
for
storage
vessels
for
petroleum
liquids;
subpart
GGG

Standards
of
Performance
for
Equipment
Leaks
of
VOC
in
Petroleum
Refineries,
and
the
Standards
of
Performance
for
VOC
Emissions
from
Petroleum
Refinery
Wastewater
Systems.
The
regulations
that
have
already
been
promulgated
also
include
a
number
of
NESHAPs,
(
40
CFR
61):

subpart
J

NESHAP
for
Equipment
Leaks
(
Fugitive
Emission
Sources)
of
Benzene;
subpart
Y

NESHAP
for
Benzene
Emissions
from
Benzene
Storage
Vessels;
and
subpart
FF

NESHAP
for
Benzene
Waste
Operations
(
BWON).

This
petroleum
refinery
NESHAP
generally
covers
refinery
processes
that
produce
petroleum
liquids
(
such
as
motor
gasoline,

naphthas,
and
kerosene)
for
use
as
fuels.
Often,
products
of
refinery
processes
are
used
to
make
synthetic
organic
chemicals
other
than
fuels.
The
petroleum
refinery
NESHAP
will
not
cover
chemical
manufacturing
process
units
that
are
covered
under
the
SOCMI
source
category,
even
if
these
units
are
located
at
a
refinery
site.
A
SOCMI
chemical
manufacturing
process
unit
that
is
located
at
a
refinery
and
produces
one
or
more
of
the
chemicals
listed
in
the
HON
(
40
CFR
63
subpart
F,
table
1)
as
a
single
chemical
product
or
as
a
mixed
chemical
used
to
produce
24
other
chemicals
would
be
considered
a
SOCMI
process
and
would
be
subject
to
the
HON
rather
than
to
the
petroleum
refinery
NESHAP.

3.4.2
Consequences
if
EPA's
Emission
Reduction
Objectives
are
Not
Met
The
most
obvious
consequence
of
failure
to
meet
EPA's
emission
reduction
objectives
would
be
emissions
reductions
and
benefits
that
are
not
as
large
as
is
projected
in
this
report.
However,

costs
are
not
likely
to
be
as
large
either.
Whether
it
is
noncompliance
from
ignorance
or
error,
or
from
willful
intent,
or
simply
slow
compliance
due
to
owners
and/
or
operators
exercising
legal
delays,
poor
compliance
can
save
some
refineries
money.

Unless
States
respond
by
allocating
more
resources
into
enforcement,
then
poor
compliance
could
bring
with
it
smaller
aggregate
nationwide
control
costs.
EPA
has
not
included
an
allowance
for
poor
compliance
in
its
estimates
of
emissions
reductions,
due
to
the
fact
that
poor
compliance
is
unlikely.

Also,
if
the
emission
control
devices
degraded
rapidly
over
time
or
in
some
other
way
did
not
function
as
expected,
there
could
be
a
misallocation
of
resources.
This
situation
is
very
unlikely,

given
that
the
NESHAP
is
based
on
demonstrated
technology.
25
REFERENCES
1.
U.
S.
Office
of
Management
and
Budget.
Regulatory
Impact
Guidance.
Appendix
V
of
Regulatory
Program
of
the
United
States
Government.
April
1,
1991

March
31,
1992.

2.
U.
S.
Environmental
Protection
Agency.
The
Risk
Assessment
Guidelines
of
1986.
Office
of
Health
and
Environmental
Assessment.
Washington,
DC.
August
1987.

3.
U.
S.
Environmental
Protection
Agency.
National
Emission
Standards
for
Hazardous
Air
Pollutants
for
Source
Categories:
Petroleum
Refineries.
Proposed
Rule
and
Notice
of
Public
Hearing.
Draft.
Section
IV.
February
1994.
26
27
4.0
CONTROL
TECHNIQUES
AND
REGULATORY
ALTERNATIVES
The
promulgated
regulation
would
require
a
broad
range
of
control
techniques
as
options
for
compliance
with
the
standard.

Combustion
technology,
internal
floating
roofs,
and
product
recovery
devices,
including
internal
floating
roofs
and
vapor
recovery
tanks,
are
all
part
of
the
technology
requirements
for
the
Petroleum
Refinery
NESHAP.
Leak
detection
and
repair
(
LDAR)

programs
will
be
used
to
control
equipment
leaks.
This
chapter
does
not
attempt
to
be
comprehensive
in
explaining
the
technology
and
techniques
used
to
control
air
toxics
emissions
under
this
promulgated
regulation;
it
does
attempt
to
survey
what
technologies
and
techniques
are
being
used
and
how
effective
they
are.

Petroleum
refineries
differ
in
the
number,
combination,
and
design
of
their
process
units;
the
production
capacities
of
their
refining
processes;
the
type
and
characteristics
of
crude
oil
they
use;
and
the
control
equipment
they
use.
Consequently,

actual
emissions
and
characteristics
of
petroleum
refinery
facilities
vary
widely
from
refinery
to
refinery.
This
diversity
affected
the
approach
used
to
define
the
MACT
floor
for
existing
and
new
sources.

This
chapter
briefly
explains
the
control
technologies
which
are
available
to
refineries
to
comply
with
the
promulgated
regulation.
At
the
end
of
this
chapter,
a
summary
of
the
two
regulatory
alternatives
is
provided.
28
4.1
CONTROL
TECHNIQUES
This
section
presents
a
summary
of
the
control
equipment
available
for
combustion
technology,
product
recovery
devices,

LDAR
programs,
and
internal
floating
roofs.
Each
type
of
control
is
presented
separately.

4.1.1
Combustion
Technology
Combustion
control
devices,
unlike
noncombustion
control
devices,
alter
the
chemical
structure
of
the
VOC.
Destruction
of
the
VOC
by
combustion
is
complete
if
all
VOCs
are
converted
to
CO
2
and
water.
Incomplete
combustion
results
in
some
of
the
VOC
remaining
unaltered
or
being
converted
to
other
organic
compounds
such
as
aldehydes
or
acids.
If
chlorinated
or
sulfur­
containing
compounds
are
present
in
the
mixture,
the
products
of
complete
combustion
include
the
acid
components
HCl
or
SO
2,
respectively,

in
addition
to
water
and
carbon
dioxide.
Available
combustion
technology
options
include
incinerators,
flares,
and
boilers
and
process
heaters.
The
process
and
applicability
of
each
control
type
are
summarized
in
the
following
sections.

4.1.1.1
Incinerators.
Incineration
is
one
of
the
best
known
methods
of
industrial
gas
waste
disposal.
It
is
a
method
of
ultimate
disposal,
that
is,
the
constituents
to
be
controlled
in
the
waste
gas
stream
are
converted
rather
than
collected.

Provided
proper
engineering
design
is
used,
incineration
can
eliminate
the
desired
organic
chemicals
in
a
gas
stream
safely
and
cleanly.

The
heart
of
an
incinerator
is
a
combustion
chamber
in
which
the
VOC­
containing
waste
stream
is
burned.
The
temperature
required
for
combustion
is
much
higher
than
the
temperature
of
the
inlet
gas,
so
energy
is
usually
supplied
to
the
incinerator
to
raise
the
waste
gas
temperature.
This
is
accomplished
by
adding
auxiliary
fuel
(
usually
natural
gas).

The
amount
of
auxiliary
fuel
required
can
be
decreased
and
energy
efficiency
increased
by
providing
heat
exchange
between
the
inlet
stream
and
the
effluent
stream.
The
effluent
stream
containing
the
products
of
combustion,
along
with
any
inerts
that
may
have
been
present
in
or
added
to
the
inlet
stream,
can
be
29
used
to
preheat
the
incoming
waste
stream,
auxiliary
air,
or
both
via
a
"
primary",
or
recuperative,
heat
exchanger.

Auxiliary
air
may
be
required
for
combustion
if
the
requisite
oxygen
is
not
available
in
the
inlet
gas
stream.
Most
industrial
gases
that
contain
VOCs
are
dilute
mixtures
of
combustible
gases
in
air.
During
the
air
oxidation
reactor
and
distillation
processes,
the
waste
gas
stream
is
deficient
in
air.

Important
in
the
design
and
operation
of
incinerators
is
the
concentration
of
combustible
gas
in
the
waste
gas
stream.
Having
a
large
amount
of
excess
air
(
i.
e.,
in
excess
of
the
required
stoichiometric
amounts)
may
be
costly,
but
any
mixture
within
the
flammability
limits,
on
either
the
fuel­
rich
or
fuel­
lean
side
of
the
stoichiometric
mixture,
is
considered
a
fire
hazard
as
a
feed
stream
to
the
incinerator.
Therefore,
some
waste
gas
streams
are
diluted
with
air
before
incineration,
even
though
this
requires
more
fuel
in
the
incinerator.
There
are
two
types
of
incinerators:
thermal
and
catalytic.
While
much
of
what
was
discussed
above
applies
to
both,
there
are
important
differences
in
their
design
and
operation.

4.1.1.1.1
Thermal
Incinerators.
As
is
true
of
other
combustion
control
devices,
thermal
incinerators
operate
on
the
principle
that
any
VOC
heated
to
a
high
enough
temperature
in
the
presence
of
sufficient
oxygen
will
be
oxidized
to
CO
2
and
water.

The
theoretical
temperature
for
thermal
oxidation
depends
on
the
properties
of
the
VOC
to
be
combusted.
There
is
great
variation
in
theoretical
combustion
temperatures
among
different
VOCs.

There
are
three
requirements
that
must
be
met
for
a
thermal
incinerator
to
be
considered
efficient:
1)
a
high
enough
temperature
within
the
combustion
chamber
to
enable
oxidation
of
the
organic
compounds
to
proceed
rapidly
to
completion;
2)
enough
turbulence
for
good
mixing
of
the
hot
combustion
products
from
the
burner,
the
combustion
air,
and
the
organic
compounds;
and
3)

sufficient
residence
time
for
oxidation
to
reach
completion.

A
typical
thermal
incinerator
is
a
refractory­
lined
chamber
containing
a
burner
or
set
of
burners
at
one
end.
Entering
gases
are
mixed
with
the
process
vent
streams
and
the
inlet
air
in
a
premixing
chamber.
Then
the
stream
of
gases
passes
into
the
main
30
combustion
chamber.
This
chamber
is
designed
to
allow
the
mixture
enough
time
at
the
required
combustion
temperature
for
complete
oxidation
(
usually
from
0.3
to
1.0
second).
A
heat
recovery
section
is
often
added
to
increase
energy
efficiency.

Often,
inlet
combustion
air
is
preheated;
if
this
occurs,

insurance
regulations
require
the
VOC
concentration
must
be
maintained
below
25
percent
of
the
lower
explosive
limit
(
LEL)
to
minimize
the
possibility
of
explosions.
Concentrations
from
25
to
50
percent
are
permitted
given
continuous
monitoring
by
LEL
monitors.

The
required
level
of
VOC
control
of
the
waste
gas
that
must
be
achieved
within
the
time
it
spends
in
the
thermal
combustion
chamber
dictates
the
reactor
temperature.
The
shorter
the
residence
time,
the
higher
the
reactor
temperature
must
be.
Once
the
unit
is
designed
and
built,
the
residence
time
is
not
easily
changed,
so
that
the
required
reaction
temperature
becomes
a
function
of
the
particular
gaseous
species
and
the
desired
level
of
control.
These
required
combustion
reaction
temperatures
cannot
be
calculated
a
priori,
although
incinerator
vendors
can
provide
guidelines
based
on
their
extensive
experience.

Predictions
of
these
temperatures
are
further
complicated
by
the
fact
that
most
process
vent
streams
are
mixtures
of
compounds.

Good
mixing
is
also
important,
particularly
in
determining
destruction
efficiency.
Even
though
it
cannot
be
measured,

mixing
is
a
factor
of
equal
or
even
greater
importance
than
other
parameters
such
as
temperature.
The
most
feasible
and
efficient
way
to
improve
the
mixing
in
an
incinerator
is
to
adjust
it
after
start­
up.

Other
parameters
affecting
thermal
incinerator
performance
are
the
heat
content
of
the
vent
stream,
the
water
content
of
the
stream,
and
the
amount
of
excess
combustion
air
(
the
amount
of
air
above
the
stoichiometric
air
needed
for
combustion).

Combustion
of
a
vent
stream
with
a
heat
content
less
than
1.9
MJ/
m3
(
52
BTU/
scf)
usually
requires
burning
supplemental
fuel
to
maintain
the
desired
combustion
temperature.

The
maximum
achievable
VOC
destruction
efficiency
decreases
with
decreasing
inlet
VOC
concentration
because
combustion
is
31
slower
at
lower
inlet
concentrations.
Therefore,
a
VOC
weight
percentage
reduction
based
on
the
mass
rate
of
VOC
exiting
the
control
device
versus
the
mass
rate
of
VOC
entering
the
device
is
appropriate
for
vent
streams
with
VOC
concentrations
above
approximately
2,000
ppmv
(
which
corresponds
to
1,000
ppmv
VOC
in
the
incinerator
inlet
stream
since
air
dilution
is
typically
1:
1).

Thermal
incinerators
are
technically
feasible
control
devices
for
most
vent
streams.
They
are
not
recommended,
however,
for
vent
streams
with
potentially
excessive
fluctuations
in
flow
rate
(
process
upsets,
for
example),
and
for
vent
streams
containing
halogens.
The
former
case
would
require
a
flare
(
see
Section
4.1.1.2)
and
the
latter
case
would
require
additional
equipment
such
as
acid
gas
scrubbers
(
see
Section
4.1.2).

4.1.1.1.2
Types
of
Thermal
Incinerators.
The
very
simplest
type
of
thermal
incinerator
is
the
direct
flame
incinerator,
which
is
made
up
of
only
the
combustion
chamber.

Energy
recovery
devices
such
as
a
waste
gas
preheater
and
a
heat
exchanger
are
not
included
with
this
type
of
incinerator.

A
second
type
of
thermal
incinerator
is
the
recuperative
model.
Recuperative
incinerators
use
the
exit
(
product)
gas
to
preheat
the
incoming
feed
stream,
combustion
air,
or
both
via
a
heat
exchanger.
These
heat
exchangers
can
recover
up
to
70
percent
of
the
energy
(
or
enthalpy)
in
the
product
gas.
The
two
types
of
heat
exchangers
commonly
used
for
this
purpose
and
many
others
are
plate­
to­
plate
and
shell­
and­
tube.
Plate­
to­
plate
exchangers
can
be
built
to
achieve
a
variety
of
efficiencies
and
offer
high
efficiency
energy
recovery
at
lower
cost
than
shelland
tube
designs.
But
when
gas
temperatures
exceed
520
degrees
Celsius,
shell­
and­
tube
exchangers
usually
have
lower
purchase
costs
than
plate­
to­
plate
designs.
Moreover,
shell­
and­
tube
exchangers
offer
better
long­
term
structural
reliability
than
plate­
to­
plate
units.

Occasionally
it
is
desired
to
recover
some
of
the
energy
added
by
auxiliary
fuel
in
the
traditional
thermal
units
(
but
not
recovered
in
preheating
the
feed
stream).
Additional
heat
exchangers
can
be
added
to
provide
process
heat
in
the
form
of
32
low
pressure
steam
or
hot
water
for
on­
site
application.
The
need
for
this
higher
level
of
energy
recovery
will
be
dependent
upon
the
plant
site.
The
additional
heat
exchanger
is
often
provided
by
the
incineration
unit
vendor.

A
third
type
of
thermal
incinerator
is
the
regenerative
incinerator.
This
type
of
incinerator
uses
direct
contact
heat
exchangers
constructed
of
a
ceramic
material
that
can
tolerate
the
high
temperatures
needed
to
achieve
ignition
of
the
waste
stream.
The
concept
behind
this
incinerator
type
is
that
the
traditional
approach
to
energy
recovery
in
thermal
units
still
requires
a
significant
amount
of
auxiliary
fuel
to
be
burned
in
the
combustion
chamber
when
waste
gas
heating
values
are
too
low
to
sustain
the
desired
reaction
temperature
at
the
moderate
preheat
temperature
employed.
Under
these
conditions,
additional
fuel
savings
can
be
realized
in
units
with
more
complete
transfer
of
exit
stream
energy.
The
regenerative
incinerator
serves
this
purpose.

In
this
type
of
incinerator,
the
inlet
gas
first
passes
through
a
hot
ceramic
bed
thereby
heating
the
steam
to
its
ignition
temperature.
After
the
hot
gases
react
and
release
energy
in
the
combustion
chamber,
the
gases
pass
through
another
ceramic
bed,
thereby
heating
it
to
the
levels
of
the
combustion
chamber
outlet
temperature.
The
process
flows
are
then
switched,

now
feeding
the
inlet
stream
to
the
hot
bed.
This
cyclic
process
affords
very
high
energy
recovery
(
up
to
95
percent).

4.1.1.1.3
Catalytic
Incinerators.
A
catalyst
promotes
oxidation
of
some
VOCs
at
a
lower
temperature
than
that
required
for
thermal
incineration.
The
catalyst
increases
the
rate
of
the
chemical
reaction
without
becoming
permanently
altered
itself.

Catalysts
typically
used
for
VOC
incineration
include
platinum
and
palladium.
These
catalysts
work
well
for
most
organic
streams,
but
are
not
tolerant
of
compounds
containing
halogens
such
as
chlorine
and
sulfur.
Among
the
catalysts
that
have
been
developed
that
are
effective
in
the
presence
of
these
halogens
are
chromia/
alumina,
cobalt
oxide,
and
copper
oxide/
manganese
oxide.
Inert
substrates
are
coated
with
thin
layers
of
these
materials
to
provide
maximum
surface
area
for
contact
with
the
33
VOC
in
the
vent
stream.
Compounds
containing
elements
such
as
lead,
arsenic,
and
phosphorus
should,
in
general,
be
considered
poisons
for
most
oxidation
catalysts.
In
addition,
particulate
matter,
including
dissolved
minerals
in
aerosols,
can
rapidly
blind
(
deactivate)
the
pores
of
catalysts
and
deactivate
them
over
time.
Because
essentially
all
the
active
surface
of
the
catalyst
is
contained
in
relatively
small
pores,
the
particulate
matter
need
not
be
large
to
blind
the
catalyst.

For
optimal
operation,
the
volumetric
gas
flow
rate
and
the
concentration
of
combustibles
(
in
this
case,
VOCs)
should
be
constant.
Large
fluctuations
in
the
flow
rate
will
cause
the
conversion
of
the
VOCs
to
fluctuate
also.
Changes
in
the
concentration
or
type
of
organic
compounds
in
the
gas
stream
can
also
affect
the
overall
conversion
of
the
VOC
contaminants.
Most
changes
in
flow
rate,
organic
concentration,
and
chemical
composition
are
generally
the
result
of
upsets
in
the
manufacturing
process
generating
the
waste
gas
stream.

Applicability
of
catalytic
incinerators
for
control
of
VOCs
is
limited
by
the
catalyst
deactivation
sensitivity
to
the
characteristics
of
the
inlet
gas
stream.
The
vent
stream
to
be
combusted
should
not
contain
materials
that
can
poison
the
catalyst
or
deposit
on
and
block
the
reactive
sites
on
the
catalyst
surface.
In
addition,
catalytic
incinerators
are
unable
to
handle
high
inlet
concentrations
of
VOC
or
very
high
flow
rates.
Catalytic
incineration
is
generally
useful
for
concentrations
of
50
to
10,000
ppmv,
if
the
total
concentration
is
less
than
25
percent
of
the
LEL
and
for
flow
rates
of
less
than
2,820
m3/
min
(
100,000
scfm).

4.1.1.1.4
Types
of
Catalytic
Incinerators.
One
type
of
catalytic
incinerator
is
fixed­
bed.
Fixed­
bed
incinerators
come
in
two
varieties,
depending
on
the
type
of
catalyst
used:
the
monolith
and
packed­
bed.
The
monolith
catalyst
is
the
most
widespread
method
of
contacting
the
VOC­
containing
stream
with
the
catalyst.
In
this
scheme,
the
catalyst
is
a
porous
solid
block
containing
parallel,
non­
intersecting
channels
aligned
in
the
direction
of
the
gas
flow.
Monolith
catalysts
offer
the
34
advantages
of
minimal
attrition
due
to
thermal
expansion/
contraction
during
startup/
shutdown
and
low
overall
pressure
drop.

A
second
contacting
scheme
is
a
simple
packed­
bed
in
which
catalyst
particles
are
supported
either
in
a
tube
or
in
shallow
trays
through
which
the
gases
pass.
The
tray
type
arrangement
is
the
more
common
packed­
bed
scheme
due
to
the
use
of
pelletized
catalysts.
This
tray
arrangement
is
preferred
because
pelletized
catalysts
can
handle
inlet
streams
containing
contaminants
such
as
phosphorus
or
silicon.
The
tube
arrangement
is
not
used
widely
due
to
its
inherently
high
pressure
drop
compared
with
a
monolith,
and
the
breaking
of
catalyst
particles
due
to
thermal
expansion
when
the
confined
catalyst
bed
is
heated/
cooled
during
startup/
shutdown.

A
third
contacting
pattern
between
the
gas
and
catalyst
is
a
fluid­
bed.
Fluid­
beds
have
the
advantage
of
very
high
mass
transfer
rates,
although
the
overall
pressure
drop
is
somewhat
higher
than
for
a
monolith.
Fluid­
beds
also
possess
the
advantage
of
high
bed­
side
heat
transfer
compared
with
a
normal
gas
heat
transfer
coefficient.
This
higher
heat
transfer
rate
to
heat
transfer
tubes
immersed
in
the
bed
allows
higher
heat
release
rates
per
unit
volume
of
gas
processed
and
therefore
may
allow
waste
gases
with
higher
heating
values
to
be
processed
without
exceeding
maximum
permissible
temperatures
in
the
catalyst
bed.
The
catalyst
temperatures
depend
on
the
rate
of
reaction
occurring
at
the
catalyst
surface
and
the
rate
of
heat
exchange
between
the
catalyst
and
imbedded
heat
transfer
surfaces.

In
general,
fluid­
bed
systems
are
more
tolerant
of
particulates
in
the
gas
stream
than
fixed­
bed
or
packed­
bed
systems.
This
results
from
the
constant
abrasion
of
the
fluidized
catalyst
pellets,
which
helps
remove
these
particulates
from
the
exterior
of
the
catalysts
in
a
continuous
manner.

4.1.1.2
Flares.
Flaring
is
an
open
combustion
process
in
which
the
oxygen
necessary
for
combustion
is
provided
by
the
air
around
the
flame.
The
organic
compounds
to
be
combusted
are
piped
to
a
remote,
usually
elevated,
location
and
burned
in
an
35
open
flame
in
the
open
air
using
a
specially
designed
burner
tip,

auxiliary
fuel,
and
sometimes
steam
or
air
to
promote
mixing
for
nearly
complete
(
98
percent
minimum)
destruction
of
combustibles.

Good
combustion
in
a
flare
is
governed
by
flame
temperature,

residence
time
of
organic
species
in
the
combustion
zone,

turbulent
mixing
of
the
organic
species
to
complete
the
oxidation
reaction,
and
the
amount
of
oxygen
available
for
free
radical
formation.
Combustion
is
complete
if
all
combustibles
(
i.
e.,

VOCs)
are
converted
to
CO
2
and
water,
while
incomplete
combustion
results
in
some
of
the
VOCs
being
unaltered
or
converted
to
other
organic
compounds
such
as
aldehydes
or
acids.

Flares
are
generally
categorized
in
two
ways:
1)
by
the
height
of
the
flare
tip
(
i.
e.,
ground­
level
or
elevated),
and
2)

by
the
method
of
enhancing
mixing
at
the
flare
tip
(
i.
e.,

steamassisted
air­
assisted,
pressure­
assisted,
or
unassisted).

Elevating
the
flare
can
prevent
potentially
dangerous
conditions
at
ground
level
where
the
open
flame
is
located
near
a
process
unit.
Further,
the
products
of
combustion
can
be
dispersed
above
working
areas
to
reduce
the
effects
of
noise,
heat
radiation,

smoke,
and
objectionable
odors.

In
most
flares,
combustion
occurs
by
means
of
a
diffusion
flame.
A
diffusion
flame
is
one
in
which
air
diffuses
across
the
boundary
of
the
fuel/
combustion
product
stream
toward
the
center
of
the
fuel
flow,
forming
the
envelope
of
a
combustible
gas
mixture
around
a
core
of
fuel
gas.
This
mixture,
on
ignition,

establishes
a
stable
flame
zone
around
the
gas
core
above
the
burner
tip.
This
inner
gas
core
is
heated
by
diffusion
of
hot
combustion
products
from
the
flame
zone.

Cracking
can
occur
with
the
formation
of
small
hot
particles
of
carbon
that
give
the
flame
its
characteristic
luminosity.
If
there
is
an
oxygen
deficiency
and
if
the
carbon
particles
are
cooled
to
below
their
ignition
temperature,
smoking
occurs.
In
large
diffusion
flames,
combustion
product
vortices
can
form
around
burning
portions
of
the
gas
and
shut
off
the
supply
of
oxygen.
This
localized
instability
causes
flame
flickering,

which
can
be
accompanied
by
soot
formation.
36
Flares
can
be
dedicated
to
almost
any
VOC
stream,
and
can
handle
fluctuations
in
VOC
concentration,
flow
rate,
heating
value,
and
inerts
content.
Flaring
is
appropriate
for
continuous,
batch,
and
variable
flow
vent
stream
applications.

Some
streams,
such
as
those
containing
halogenated
or
sulfurcontaining
compounds,
are
usually
not
flared
because
they
corrode
the
flare
tip
or
cause
formation
of
secondary
pollutants
(
such
as
acid
gases
or
sulfur
dioxide).
If
these
vent
types
are
to
be
controlled
by
combustion,
thermal
incineration,
followed
by
scrubbing
to
remove
the
acid
gases,
is
the
preferred
method.

The
majority
of
refineries
have
existing
flare
systems
designed
to
relieve
emergency
process
upsets
that
might
contain
large
gas
volumes.
Often,
large
diameter
flares
designed
to
handle
emergency
releases
are
also
used
to
control
continuous
vent
streams
from
various
process
operations.
Typically
in
refineries,
many
vent
streams
are
combined
in
a
common
gas
header
to
fuel
boilers
and
process
heaters.
However,
excess
gases,

fluctuations
in
flow
rate
in
the
fuel
gas
line,
and
emergency
releases
are
sometimes
sent
to
a
flare.
Five
factors
affecting
flare
combustion
efficiency
are
vent
gas
flammability,

autoignition
temperature,
heat
content
of
the
vent
stream,
density,

and
flame
zone
mixing.

The
flammability
limits
of
the
vent
stream
influence
ignition
stability
and
flame
extinction.
Flammability
limits
are
the
stoichiometric
composition
limits
(
maximum
and
minimum)
of
an
oxygen­
fuel
mixture
that
will
burn
indefinitely
at
given
conditions
of
temperature
and
pressure
without
further
ignition.

In
other
words,
gases
must
be
within
their
flammability
limits
to
burn.
If
these
limits
are
narrow,
the
interior
of
the
flame
may
have
insufficient
air
for
the
mixture
to
burn.
Fuels,
such
as
hydrogen,
with
wide
limits
of
flammability
are
therefore
easier
to
combust.

The
auto­
ignition
temperature
of
a
vent
stream
affects
combustion
because
gas
mixtures
must
be
at
a
sufficient
temperature
and
concentration
to
burn.
A
gas
with
a
low
autoignition
temperature
will
ignite
more
easily
than
a
gas
with
a
high
auto­
ignition
temperature.
37
The
heat
content
of
the
vent
stream
is
a
measure
of
the
heat
available
from
the
combustion
of
the
VOC
in
the
vent
stream.
The
heat
content
of
the
vent
stream
affects
the
flame
structure
and
stability.
A
gas
with
a
lower
heat
content
produces
a
cooler
flame
that
does
not
favor
combustion
kinetics
and
is
more
easily
extinguished.
The
lower
flame
temperature
will
also
reduce
buoyant
forces,
which
reduces
mixing.

The
density
of
the
vent
stream
also
affects
the
structure
and
stability
of
the
flame
through
the
effect
on
buoyancy
and
mixing.

By
design,
the
velocity
in
many
flares
is
very
low;
therefore,

most
of
the
flame
structure
is
developed
through
buoyant
forces
as
a
result
of
combustion.
Lighter
gases
therefore
tend
to
burn
better.
In
addition
to
burner
tip
design,
the
density
also
affects
the
minimum
purge
gas
required
to
prevent
flashback,
with
lighter
gases
requiring
more
purge.

Poor
mixing
at
the
flare
tip
or
poor
flare
maintenance
can
cause
smoking
(
particulate
matter
release).
Vent
streams
with
high
carbon­
to­
hydrogen
ratios
(>
0.35)
have
a
greater
tendency
to
smoke
and
require
better
mixing
to
burn
smokelessly.
For
this
reason,
one
generic
steam­
to­
vent­
stream
ratio
is
not
appropriate
for
all
vent
streams.
The
steam
required
depends
on
the
vent
stream
carbon­
to­
hydrogen
ratio.
A
high
ratio
requires
more
steam
to
prevent
a
smoking
flare.

The
efficiency
of
a
flare
in
reducing
VOC
emissions
can
be
variable.
For
example,
smoking
flares
are
far
less
efficient
than
properly
operated
and
maintained
flares.
Flares
have
been
shown
to
have
high
VOC
destruction
efficiencies,
under
proper
operating
conditions.
Up
to
99.7
percent
combustion
efficiency
can
be
achieved.

4.1.1.2.1
Steam­
Assisted
Flares.
Steam­
assisted
flares
are
single
burner
tips,
elevated
above
ground
level
for
safety
reasons,
that
burn
the
vented
gas
in
essentially
a
diffusion
flame.
They
reportedly
account
for
the
majority
of
the
flames
installed
and
are
the
predominant
flare
type
found
in
refineries.

To
ensure
an
adequate
air
supply
and
good
mixing,
this
type
of
flare
system
injects
steam
into
the
combustion
zone
to
promote
turbulence
for
mixing
and
to
induce
air
into
the
flame.
38
4.1.1.2.2
Air­
Assisted
Flares.
Air­
assisted
flares
use
forced
air
to
provide
the
combustion
air
and
the
mixing
required
for
smokeless
operation.
These
flares
are
built
with
a
spidershaped
burner
(
with
many
small
gas
orifices)
located
inside
but
near
the
top
of
a
steel
cylinder
two
feet
or
more
in
diameter.

Combustion
air
is
provided
by
a
fan
in
the
bottom
of
the
cylinder,
and
the
amount
of
combustion
air
can
be
varied
by
changing
the
fan
speed.
The
primary
advantage
air­
assisted
flares
provide
is
that
they
can
be
used
without
steam.

4.1.1.2.3
Non­
Assisted
Flares.
The
non­
assisted
flare
is
just
a
flare
tip
without
any
auxiliary
provision
for
enhancing
the
mixing
of
air
into
its
flame.
Its
use
is
limited
essentially
to
gas
streams
that
have
a
low
heat
content
and
a
low
carbon/
hydrogen
ratio
that
burn
readily
without
producing
smoke.

These
streams
require
less
air
for
complete
combustion,
have
lower
combustion
temperatures
that
minimize
cracking
reactions,

and
are
more
resistant
to
cracking.

4.1.1.2.4
Pressure­
Assisted
Flares.
This
type
of
flare
uses
vent
stream
pressure
to
promote
mixing
at
the
burner
tip.
If
sufficient
vent
stream
pressure
is
available,
these
flares
can
be
applied
to
streams
previously
requiring
steam
or
air
assist
for
smokeless
operation.
Pressure­
assisted
flares
generally
have
the
burner
arrangement
at
ground
level,
and
consequently,
must
be
located
in
a
remote
area
of
the
plant
where
there
is
plenty
of
space
available.
They
have
multiple
burner
heads
that
are
staged
to
operate
based
on
the
quantity
of
gas
being
released.
The
size,
design,
number,
and
group
arrangement
of
the
burner
heads
depend
on
the
vent
gas
characteristics.

4.1.1.2.5
Enclosed
Ground
Flares.
The
burner
heads
of
an
enclosed
flare
are
inside
an
insulated
shell.
This
shell
reduces
noise,
luminosity,
and
heat
radiation
and
provides
wind
protection.
A
high
nozzle
pressure
drop
is
usually
adequate
to
provide
the
mixing
necessary
for
smokeless
operation
and
air
or
steam
assist
is
not
required.
In
this
context,
enclosed
flares
can
be
considered
a
special
class
of
pressure­
assisted
or
nonassisted
flares.
Enclosed
flares
are
always
at
ground
level.
39
Enclosed
flares
generally
have
less
capacity
than
open
flares
and
are
used
to
combust
continuous,
constant
flow
vent
streams,

although
reliable
and
efficient
operation
can
be
attained
over
a
wide
range
of
design
capacity.
Stable
combustion
can
be
obtained
with
lower
heat
content
vent
gases
than
is
possible
with
open
flare
designs,
probably
due
to
their
isolation
from
wind
effects.

4.1.1.3
Boilers
and
Process
Heaters.
Industrial
boilers
are
combustion
units
that
boil
water
to
produce
high
and
low
pressure
steam.
Industrial
boilers
can
also
combust
various
vent
streams
containing
VOCs,
including
vent
streams
from
distillation
operations,
reactor
processes,
and
other
general
operations.
The
majority
of
industrial
boilers
used
in
the
refining
industry
are
of
watertube
design,
and
over
half
of
these
boilers
use
natural
gas
as
a
fuel.
In
a
watertube
boiler,
hot
combustion
gases
contact
the
outside
of
heat
transfer
tubes
which
contain
hot
water
and
steam.
These
tubes
are
interconnected
by
a
set
of
drums
that
collect
and
store
the
heated
water
and
steam.
Energy
transfer
from
the
hot
flue
gases
to
the
water
in
the
furnace
watertube
and
drum
system
can
be
better
than
85
percent
efficient.
Additional
energy
can
be
recovered
from
the
flue
gas
by
preheating
combustion
air
in
an
air
preheater
or
by
preheating
incoming
boiler
feed
water
in
an
economizer
unit.

When
firing
natural
gas,
forced­
or
natural­
draft
burners
thoroughly
mix
the
incoming
fuel
and
combustion
air.
A
VOCcontaining
vent
stream
can
be
added
to
this
mixture
or
it
can
be
fed
into
the
boiler
through
a
separate
burner.
In
general,

burner
design
depends
on
the
characteristics
of
the
fuel

either
the
combined
VOC­
containing
vent
stream
and
fuel,
or
the
vent
stream
alone
(
when
a
separate
burner
is
used).

A
process
heater
is
similar
to
an
industrial
boiler
in
that
heat
liberated
by
the
combustion
of
fuels
is
transferred
by
radiation
and
convection
to
fluids
contained
in
tubular
coils.

It
is
different
from
an
industrial
boiler
in
that
process
heaters
raise
the
temperature
of
process
streams
instead
of
producing
high
temperature
steam.
Process
heaters
are
used
in
many
chemical
manufacturing
operations
to
drive
endothermic
reactions.

They
are
also
used
as
feed
preheaters
and
as
reboilers
for
some
40
distillation
operations.
The
fuels
used
in
process
heaters
include
natural
gas,
refinery
offgases,
and
various
grades
of
fuel
oil.

A
typical
process
heater
design
consists
of
the
burner(
s),
the
firebox,
and
a
row
of
tubular
coils
containing
the
process
fluid.

Most
heaters
also
contain
a
convective
section
in
which
heat
is
recovered
from
hot
combustion
gases
by
convective
heat
transfer
to
the
process
fluid.

4.1.1.3.1
Efficiency
of
Boilers
and
Process
Heaters.
Average
furnace
temperature
and
residence
time
determine
the
combustion
efficiency
of
boilers
and
process
heaters,
just
as
they
do
for
incinerators.
When
a
vent
gas
is
injected
as
a
fuel
into
the
flame
zone
of
a
boiler
or
process
heater,
the
required
residence
time
is
reduced
because
of
the
relatively
high
temperature
and
turbulence
of
the
flame
zone.

Residence
time
and
temperature
profiles
in
boilers
and
process
heaters
are
determined
by
factors
such
as
overall
configuration,

fuel
type,
heat
input,
and
excess
air
level.
A
mathematical
model
developed
to
estimate
furnace
residence
time
and
temperature
profiles
for
a
variety
of
industrial
boilers
predicts
mean
furnace
residence
times
ranging
0.25
to
0.83
second
for
natural
gas­
fired
watertube
boilers
that
range
in
size
from
4.4
to
44
MW
(
15
to
150
x
106
Btu/
hr).
Boilers
with
a
44­
MW
capacity
or
greater
generally
have
residence
times
and
operating
temperatures
that
would
ensure
a
98
percent
VOC
destruction
efficiency.
The
required
temperatures
for
these
size
boilers
are
at
least
1,200
degrees
Celsius.

Firebox
temperatures
for
process
heaters
can
show
wide
variations
depending
on
the
application.
Firebox
temperatures
can
range
from
400
degrees
Celsius
for
preheaters
and
reboilers
to
1,260
degrees
Celsius
for
pyrolysis
furnaces.
Tests
conducted
by
EPA
on
process
heaters
using
a
mixture
of
benzene
offgas
and
natural
gas
showed
greater
than
98
percent
destruction
efficiency
for
C
1
to
C
6
hydrocarbons.

4.1.1.3.2
Applicability
of
Boilers
and
Process
Heaters.
Both
of
these
devices
are
used
throughout
petroleum
refineries
to
provide
steam
and
heat
input
essential
to
the
refining
process.
41
Most
of
these
devices
possess
sufficient
size
to
provide
the
necessary
temperature
and
residence
time
for
VOC
destruction.

Furthermore,
boilers
and
process
heaters
have
proved
effective
in
destroying
compounds
that
are
difficult
to
combust,
such
as
PCBs
(
polychlorinated
biphenyls).
Boilers
and
process
heaters
are
thus
effective
in
reducing
VOC
emissions
from
any
vent
streams
that
are
certain
not
to
reduce
the
performance
or
reliability
of
the
boiler
or
process
heater.

Ducting
some
vent
streams
to
a
boiler
or
process
heater
can
present
potential
safety
and
operating
problems.
The
varying
flow
rate
and
organic
content
of
some
vent
streams
can
lead
to
explosive
mixtures
or
flame
instability
within
the
furnace.
In
addition,
vent
streams
with
halogenated
or
sulfur­
containing
compounds
are
usually
not
combusted
in
boilers
or
process
heaters
due
to
the
possibility
of
corrosion.

Boilers
and
process
heaters
are
most
applicable
where
the
potential
exists
for
heat
recovery
from
the
combustion
of
the
vent
stream.
Vent
streams
with
a
high
enough
VOC
concentration
and
high
flow
rate
can
provide
enough
equivalent
heat
value
to
act
as
a
substitute
for
fuel
that
would
otherwise
be
needed.

Because
boilers
and
process
heaters
cannot
tolerate
wide
fluctuations
or
interruptions
in
the
fuel
supply,
they
are
not
widely
used
to
reduce
VOC
emissions
from
batch
operations
or
other
noncontinuous
vent
streams.

4.1.2
Product
Recovery
Devices
4.1.2.1
Absorbers.
In
absorption,
a
soluble
vapor
is
absorbed
from
its
mixture
with
an
inert
gas
by
means
of
a
liquid
in
which
the
solute
gas
is
more
or
less
soluble.
For
any
given
solvent,
solute,
and
operating
conditions,
there
exists
an
equilibrium
ratio
of
solute
concentration
in
the
gas
mixture
to
solute
concentration
in
the
solvent.
The
driving
force
for
mass
transfer
at
a
given
point
in
an
operating
absorber
is
the
difference
between
the
concentration
of
solute
in
the
gas
and
the
equilibrium
concentration
of
solute
in
the
liquid.
42
Devices
based
on
absorption
principles
include
spray
towers,

venturi
and
wet
impingement
scrubbers,
acid
gas
scrubbers,
packed
columns,
and
plate
columns.
Spray
towers
have
the
least
effective
mass
transfer
capability
due
to
their
high
atomization
pressure
requirement,
and
are
generally
restricted
to
particulate
matter
removal
and
control
of
high­
solubility
gases
such
as
SO
2
and
NH
3
(
ammonia).
Venturi
scrubbers
have
a
high
degree
of
gas/
liquid
mixing
and
provide
high
particulate
matter
removal
efficiency.
They
also
require
high
pressure
drops
(
i.
e.
high
energy
requirements)
and
have
relatively
short
contact
times.

Their
use
is
also
restricted
to
high­
solubility
gases.
Acid
gas
scrubbers
are
used
with
thermal
incinerators
to
remove
corrosive
combustion
products.
Acid
gas
is
formed
upon
the
contact
of
halogenated
or
sulfur­
containing
VOCs
with
intense
heat
during
incineration.
This
gas
is
quenched
to
lower
its
temperature
and
is
then
scrubbed
in
an
absorber.
In
most
cases,
the
type
of
absorber
used
is
packed
or
plate
columns,
the
two
most
commonly
used
absorbers
for
VOC
control.

Packed
towers
are
vertical
columns
containing
inert
packing,

manufactured
from
materials
such
as
porcelain,
metal,
or
plastic,

that
provides
the
surface
area
for
contact
between
the
liquid
and
gas
phases
in
the
absorber.
Packed
towers
are
used
mainly
for
corrosive
materials
and
liquids
with
tendencies
to
foam
or
plug.

They
are
less
expensive
than
plate
columns
for
small­
scale
or
pilot
plant
operations
where
the
column
diameter
is
less
than
0.6
m.
They
are
also
suitable
where
the
use
of
plate
columns
would
result
in
excessive
pressure
drops.

Plate
columns
contain
a
series
of
trays
on
which
contact
between
the
gas
and
liquid
phases
in
a
stepwise
fashion.
The
liquid
phase
flows
down
tray
to
tray
as
the
gas
phase
moves
up
through
openings
in
the
tray
(
usually
perforations
or
bubble
caps),
passing
through
the
liquid
on
the
way.

The
major
design
parameters
for
absorbing
any
substance
are
column
diameter
and
height,
system
pressure
drop,
and
required
liquid
flow
rate.
Deriving
these
parameters
is
accomplished
by
considering
the
solubility,
viscosity,
density,
and
concentration
of
the
VOC
in
the
inlet
vent
stream
(
all
of
which
depend
on
43
column
temperature);
the
total
surface
area
provided
by
the
packing
material;
and
the
mass
flow
rate
of
the
gases
to
be
treated.

4.1.2.1.1
Absorber
Efficiency.
Control
efficiencies
for
absorbers
can
vary
widely
depending
on
the
solvent
selected,

design
parameters,
and
operating
practices.
Solvents
are
chosen
for
high
solubility
for
the
specific
VOC
and
include
liquids
such
as
water,
mineral
oils,
kerosenes,
nonvolatile
hydrocarbon
oils,

and
aqueous
solutions
of
oxidizing
agents,
sodium
carbonate,
and
sodium
carbonate.
An
increase
in
absorber
size
(
i.
e.,
contact
surface
area)
or
a
decrease
in
the
operating
temperature
can
increase
the
VOC
removal
efficiency
of
the
system
for
a
given
solvent
and
solute.
It
is
sometimes
possible
to
increase
VOC
removal
efficiency
by
changing
the
solvent.

4.1.2.1.2
Applicability.
The
primary
determinant
of
absorption
applicability
for
controlling
VOC
emissions
is
the
availability
of
a
suitable
solvent.
Water
is
a
suitable
solvent
for
absorption
of
organic
chemicals
with
relatively
high
water
solubilities
(
e.
g.,
most
alcohols,
organic
acids,
aldehydes,

glycols).
For
organic
compounds
with
low
water
solubilities,

other
solvents
(
usually
organic
liquids
with
low
vapor
pressures)

are
used.

Other
important
factors
influencing
absorption
applicability
include
absorptive
capacity
and
strippability
of
VOC
in
the
solvent.
Absorptive
capacity
is
a
measure
of
the
solubility
of
VOC
in
the
solvent.
The
solubility
limits
the
total
quantity
of
VOC
that
could
be
absorbed
in
the
system,
while
strippability
describes
the
ease
with
which
the
VOC
can
be
removed
from
the
solvent.
If
strippability
is
low,
then
absorption
is
less
viable
as
a
VOC
control
technique.

The
concentration
of
VOC
in
the
inlet
vent
stream
also
determines
the
applicability
of
absorption.
Absorption
is
usually
considered
only
when
the
VOC
concentration
is
above
200
to
300
ppm.
Below
these
gas­
phase
concentrations,
the
rate
of
mass
transfer
of
VOC
to
solvent
is
decreased
enough
to
make
reasonable
designs
infeasible.
44
4.1.2.2
Carbon
Adsorbers.
Adsorption
is
a
mass­
transfer
operation
involving
interaction
between
gas­
or
liquid­
phase
components
and
solid­
phase
components.
In
this
operation,

certain
components
of
a
gas­
or
liquid­
phase
(
or
adsorbate)
are
transferred
to
the
surface
of
a
solid
adsorbent.
The
transfer
is
accomplished
by
physical
or
chemical
adsorption
mechanisms.

Physical
adsorption
takes
place
when
intermolecular
(
van
der
Waals)
forces
attract
and
hold
the
gas
molecules
to
the
solid
surface.
Chemisorption
occurs
when
a
chemical
bond
forms
between
the
gaseous­
and
solid­
phase
molecules.
A
physically
adsorbed
molecule
can
be
removed
readily
from
the
adsorbent
(
under
suitable
temperature
and
pressure
conditions);
the
removal
of
a
chemisorbed
component
is
much
more
difficult.

Most
industrial
adsorption
systems
use
activated
carbon
as
the
adsorbent.
Activated
carbon
effectively
captures
certain
organic
vapors
by
physical
adsorption.
The
vapors
can
then
be
released
for
recovery
by
regenerating
the
adsorption
bed
with
steam
or
nitrogen.
Oxygenated
adsorbents
such
as
silica
gels
or
diatomaceous
earth
exhibit
a
greater
selectivity
for
capturing
water
vapor
than
organic
gases
compared
to
activated
carbon.

They
thus
are
of
little
use
for
high­
moisture
vent
streams
characteristic
of
some
VOC­
containing
vent
streams.

Among
the
factors
influencing
the
design
of
a
carbon
adsorption
system
are
the
chemical
characteristics
of
the
VOC
being
recovered,
the
physical
properties
of
the
inlet
stream
(
temperature,
pressure,
and
volumetric
flow
rate),
and
the
physical
properties
of
the
adsorbent.
The
mass
of
VOC
that
adheres
to
the
adsorbent
surface
is
directly
proportional
to
the
difference
in
VOC
concentration
between
the
gas
phase
and
the
solid
surface.
In
addition,
the
quantity
of
VOC
adsorbed
depends
on
the
adsorbent
bed
volume,
the
surface
area
of
adsorbent
available
to
capture
VOC,
and
the
rate
of
diffusion
of
VOC
through
the
gas
film
at
the
gas­
and
solid­
phase
interface
(
the
mass
transfer
coefficient).
It
should
be
noted
that
physical
adsorption
is
an
exothermic
operation
that
is
most
efficient
within
a
narrow
range
of
temperature
and
pressure.
45
4.1.2.3.1
Types
of
Adsorbers.
There
are
five
types
of
adsorption
equipment
used
in
gas
collection:
1)
fixed
regenerable
beds;
2)
disposable/
rechargeable
canisters;

3)
traveling
bed
adsorbers;
4)
fluid
bed
adsorbers;
and
5)

chromatographic
baghouses.
The
fixed­
bed
type
is
the
one
most
commonly
used
for
control
of
VOCs,
so
this
section
addresses
this
type
only.

Fixed­
bed
units
can
be
sized
for
controlling
continuous,

VOCcontaining
streams
over
a
wide
range
of
flow
rates,
ranging
up
to
several
thousand
cubic
meters
per
minute
(
100,000
scfm).
VOC
concentrations
in
streams
that
can
be
treated
by
fixed­
bed
units
can
range
from
several
parts
per
billion
by
volume
(
ppbv)
to
10,000
ppmv.

Fixed­
bed
adsorbers
can
be
operated
in
two
modes:

intermittent
or
continuous.
In
intermittent
mode,
the
adsorber
removes
VOCs
for
a
specified
time
(
called
"
the
adsorption
time"),

which
corresponds
to
the
time
during
which
the
controlled
source
is
emitting
VOCs.
In
continuous
mode,
a
regenerated
carbon
bed
is
always
available
for
adsorption,
so
that
the
controlled
source
can
operate
continuously
without
shutting
down.
While
continuous
operation
allows
for
more
adsorption
over
the
same
period
of
time
because
it
does
not
need
to
be
shut
down,
more
carbon
must
be
provided.
This
is
necessary
since
a
bed
for
desorbing
must
be
provided
along
with
the
adsorbing
bed
in
order
to
recover
the
captured
VOC
from
the
carbon.

4.1.2.3.2
Control
Efficiency.
Well
designed
and
operated
carbon
adsorption
systems
can
achieve
control
efficiencies
of
95
to
99
percent
for
a
variety
of
solvents
including
ketones
such
as
methyl
ethyl
ketone
and
cyclohexanone.
The
VOC
control
efficiency
depends
on
factors
such
as
inlet
vent
stream
characteristics
(
temperature,
pressure,
and
velocity),
the
physical
properties
of
the
compounds
present
in
the
vent
stream,

the
physical
properties
of
the
adsorbent,
and
the
condition
of
the
regenerated
carbon
bed.

The
adsorption
capacity
of
the
carbon
and
the
resulting
outlet
concentration
are
dependent
upon
the
temperature
of
the
inlet
vent
stream.
High
vent
stream
temperatures
increase
the
kinetic
46
energy
of
the
gas
molecules,
causing
them
to
overcome
van
der
Waals
forces
and
release
from
the
surface
of
the
carbon.
At
vent
stream
temperatures
above
38
degrees
Celsius,
both
adsorption
capacity
and
outlet
concentration
may
be
adversely
affected.

Increasing
vent
stream
pressure
improves
VOC
removal
efficiency.
Increased
stream
pressure
results
in
higher
VOC
concentrations
in
the
vapor
phase
and
increased
driving
force
for
mass
transfer
to
the
carbon
surface.
Decreased
stream
pressure,

on
the
other
hand,
is
often
used
to
regenerate
carbon
beds.

Reduced
pressure
in
the
carbon
bed
effectively
lowers
the
concentration
of
VOCs
in
the
vapor
phase,
desorbing
the
VOCs
from
the
carbon
surface
to
the
vapor
phase.

Vent
stream
velocity
entering
the
carbon
bed
must
be
quite
low
to
allow
time
for
diffusion
and
adsorption.
Typical
inlet
vent
stream
velocities
range
from
15
to
30
meters
per
minute
(
50
to
100
feet
per
minute).
If
inlet
VOC
concentrations
are
low,
the
bed
area
required
for
the
volume
needed
usually
permits
a
velocity
at
the
high
end
of
this
range.
The
required
depth
of
the
bed
for
a
given
compound
is
directly
proportional
to
the
carbon
granule
size
and
porosity
and
to
the
inlet
vent
stream
velocity.
For
a
given
carbon
type,
bed
depth
must
increase
as
the
vent
stream
velocity
increases.
Generally,
carbon
adsorber
bed
depths
range
from
0.40
to
0.95
meter
(
1.5
to
3.0
feet).
The
condition
of
the
regenerated
carbon
bed
will
change
with
use.

After
repeated
regeneration,
the
carbon
bed
loses
activity,

resulting
in
reduced
VOC
removal
efficiency.

4.1.2.3.3
Applicability.
Carbon
adsorption
cannot
be
used
universally
for
distillation
or
process
vent
streams.
It
is
not
recommended
under
the
following
conditions,
common
with
many
VOCcontaining
vent
streams:
1)
high
VOC
concentrations,
2)
very
high
or
low
molecular
weight
compounds,
3)
mixtures
of
high
and
low
boiling
point
VOCs,
and
4)
high
moisture
content.

Absorbing
vent
streams
with
VOC
concentrations
above
10,000
ppmv
may
result
in
excessive
temperature
rise
in
the
carbon
bed
due
to
the
accumulated
heat
of
adsorption
resulting
from
the
VOC
loading.
If
flammable
vapors
are
present,
insurance
company
47
requirements
may
limit
inlet
concentrations
to
less
than
25
percent
of
the
LEL.

The
molecular
weight
of
the
compounds
to
be
adsorbed
should
be
in
the
range
of
45
to
130
gm/
gm­
mole
for
effective
adsorption.

High
molecular
weight
compounds
that
are
characterized
by
low
volatility
are
strongly
adsorbed
on
carbon.
The
affinity
of
carbon
for
these
compounds
makes
it
difficult
to
remove
them
during
regeneration
of
the
carbon
bed.
Conversely,
highly
volatile
materials
(
i.
e.,
molecular
weight
less
than
about
45
gm)

do
not
adsorb
readily
on
carbon,
thus
adsorption
is
not
typically
used
for
controlling
streams
containing
such
compounds.

Adsorption
systems
can
be
very
effective
with
homogeneous
vent
streams
but
much
less
so
with
streams
containing
a
mixture
of
light
and
heavy
hydrocarbons.
The
lighter
organic
compounds
tend
to
be
displaced
by
the
heavier
compounds,
greatly
reducing
system
efficiency.

Humidity
is
not
a
factor
in
adsorption
at
adsorbate
concentrations
above
1,000
ppmv.
Below
this
level,
however,

water
vapor
competes
with
VOCs
in
the
vent
stream
for
adsorption
sites
on
the
carbon
surface.
In
these
cases,
vent
stream
humidity
levels
exceeding
50
percent
(
relative
humidity)
are
not
desirable.

4.1.2.4
Condensers.
Condensation
is
a
separation
technique
in
which
one
or
more
volatile
components
of
a
vapor
mixture
are
separated
from
the
remaining
vapors
through
saturation
followed
by
a
phase
change.
The
phase
change
from
gas
to
liquid
can
be
achieved
in
two
ways:
1)
by
increasing
the
system
pressure
at
a
given
temperature
or
2)
by
lowering
the
temperature
at
a
constant
pressure.
The
latter
method
is
the
more
common
to
achieve
the
specified
phase
change,
and
it
alone
is
addressed
here.

The
basic
equipment
includes
a
condenser,
refrigeration
unit(
s),
and
auxiliary
equipment
such
as
a
pre­
cooler,

recovery/
storage
tank,
pump/
blower,
and
piping.
The
two
most
commonly
used
condenser
types
are
surface
condensers
and
direct
contact
condensers.
In
surface
condensers,
the
coolant
fluid
does
not
contact
the
vent
stream;
heat
transfer
occurs
through
48
the
tubes
or
plates
in
the
condenser.
As
the
vapor
condenses,
a
film
forms
on
the
cooled
surface
and
drains
away
to
a
collection
tank
for
storage,
reuse,
or
disposal.
Because
the
coolant
from
surface
condensers
does
not
contact
the
vapor
stream,
it
is
not
contaminated
and
can
be
recycled
in
a
closed
loop.
Surface
condensers
also
allow
for
direct
recovery
of
VOCs
from
the
gas
stream.

Most
refrigerated
surface
condensers
are
the
shell­
and­
tube
type,
which
circulates
the
coolant
fluid
on
the
tube
side.
The
VOCs
condense
on
the
outside
of
the
tube
(
the
shell
side).

Plate­
type
heat
exchangers
are
also
used
as
surface
condensers
in
refrigerated
systems.
Plate
condensers
operate
under
the
same
principles
as
the
shell­
and­
tube
systems,
for
there
is
no
contact
between
the
coolant
and
vent
stream),
but
the
two
streams
are
separated
by
thin,
flat
plates
instead
of
cylindrical
tubes.

In
contrast
to
surface
condensers,
direct
contact
condensers
cool
the
vapor
stream
by
spraying
a
liquid
at
ambient
or
lower
temperature
directly
into
the
vent
stream.
Spent
coolant
containing
VOCs
from
direct
contact
condensers
usually
cannot
be
reused
directly.
Additionally,
VOCs
in
the
spent
coolant
cannot
be
recovered
without
further
processing.
The
combined
stream
could
present
a
potential
waste
disposal
problem,
depending
upon
the
coolant
and
the
specific
VOCs.

A
refrigeration
unit
generates
the
low­
temperature
medium
necessary
for
heat
transfer
for
recovery
of
VOCs.
Typically
in
refrigerated
condenser
systems
two
kinds
of
refrigerants
are
used,
primary
and
secondary.
Primary
refrigerants
such
as
ammonia
and
chlorofluorocarbons
(
e.
g.,
chlorodifluoromethane)
are
those
that
undergo
a
phase
change
from
liquid
to
gas
after
absorbing
heat.
Secondary
refrigerants,
such
as
brine
solutions,

have
higher
boiling
points
and
thus
act
only
as
heat
carriers
and
remain
in
the
liquid
phase.

There
are
some
applications
that
require
auxiliary
equipment.

If
the
vent
stream
contains
water
vapor
or
if
the
VOC
has
a
high
freezing
point
(
e.
g.,
benzene
or
toluene),
ice
or
frozen
hydrocarbons
may
form
on
the
condenser
tubes
or
plates.
This
will
reduce
the
heat
transfer
efficiency
of
the
condenser
and
49
thereby
reduce
the
removal
efficiency.
Formation
of
ice
will
also
increase
the
pressure
drop
across
the
condenser.
In
such
cases,
a
precooler
may
be
used
to
remove
the
moisture
before
the
vent
stream
enters
the
condenser.
Alternatively,
ice
can
be
melted
during
an
intermittent
heating
cycle
by
circulating
ambient
temperature
brine
through
the
condenser
or
using
radiant
heating
coils.

It
is
necessary
in
some
cases
to
provide
a
recovery
tank
for
temporary
storage
of
condensed
VOC
before
its
reuse,

reprocessing,
or
transfer
to
a
large
storage
tank.
Pumps
and
blowers
are
typically
used
to
transfer
liquid
(
e.
g.,
coolant
and
recovered
VOC)
and
gas
streams,
respectively,
within
the
system.

4.1.2.4.1
Control
Efficiency.
The
major
parameters
that
affect
the
removal
efficiency
of
refrigerated
surface
condensers
designed
to
control
air/
VOC
mixtures
are:
1)
Volumetric
flow
rate
of
the
VOC­
containing
vent
stream;
2)
Inlet
temperature
of
the
vent
stream;
3)
Concentrations
of
the
VOCs
in
the
vent
stream;
4)
Absolute
pressure
of
the
vent
stream;
5)
Moisture
content
of
the
vent
stream;
and
6)
properties
of
the
VOCs
in
the
vent
stream,
such
as
dew
points,
heats
of
condensation,
heat
capacities,
and
vapor
pressures.

Any
operator
of
a
condenser
should
remember
that
a
condenser
cannot
lower
the
VOC
concentration
to
levels
below
the
saturation
concentration
at
the
coolant
temperature.
Removal
efficiencies
above
90
percent
can
be
achieved
with
coolants
such
as
chilled
water,
brine
solutions,
ammonia,
or
chlorofluorocarbons.

4.1.2.4.2
Applicability.
Condensers
are
widely
used
as
product
recovery
devices.
They
may
be
used
to
recover
VOCs
upstream
of
other
control
devices
or
they
may
be
used
alone
for
controlling
vent
streams
containing
relatively
high
VOC
concentrations
(
usually
greater
than
5,000
ppmv).
In
these
cases,
the
removal
efficiencies
of
condensers
can
range
widely,

from
50
to
95
percent.

Since
the
temperature
necessary
for
condensation
depends
on
the
properties
and
concentration
of
VOCs
in
the
vent
stream,

streams
having
either
low
VOC
concentrations
or
more
volatile
50
compounds
require
lower
condensation
temperatures.
Also,

depending
on
the
type
of
condenser
used,
disposal
of
the
spent
coolant
can
be
a
problem.
If
cross­
media
impacts
are
a
concern,

surface
condensers
would
be
preferable
to
direct
contact
condensers.

Condensers
used
as
emission
control
devices
can
process
flow
rates
as
high
as
about
57
m3/
min
(
120,000
scfm).
Condensers
for
vent
streams
with
greater
volumetric
flow
rates
and
having
high
concentrations
of
noncondensibles
will
require
significantly
larger
heat
transfer
areas.

4.1.3
Leak
Detection
and
Repair
Leak
detection
and
repair
(
LDAR)
programs
have
been
required
by
EPA
for
a
number
of
years.
They
have
been
undertaken
to
reduce
emissions
due
to
leaking
equipment.
These
emissions
occur
when
process
fluid
(
liquid
or
gaseous)
is
released
through
the
sealing
mechanisms
of
equipment
in
the
chemical
plant.
This
section
discusses
the
sources
of
equipment
leak
emissions
and
control
techniques
that
can
be
applied
to
reduce
emissions
from
equipment
leaks,
including
the
applicability
of
each
control
technique
and
its
associated
effectiveness
in
reducing
emissions.

Many
potential
sources
of
equipment
leak
emissions
exist
in
a
refinery.
The
following
sources
are
covered
in
this
section:

pumps,
compressors,
pressure
relief
devices,
open­
ended
lines,

sampling
connections,
process
valves,
connectors,
instrumentation
systems,
and
product
accumulator
vessels.

The
techniques
for
reducing
emissions
from
equipment
leaks
are
as
diverse
as
the
types
of
sources.
The
three
major
categories
for
techniques
are:
1)
equipment
(
modifications);
2)
closed
vent
systems;
and
3)
work
practices.
The
selection
of
a
control
technique
and
its
effectiveness
in
reducing
emissions
depends
on
a
number
of
factors
including:
1)
type
of
equipment;
2)

equipment
service
(
gas,
light
liquid,
heavy
liquid);
3)
process
variables
influencing
equipment
selection
(
temperature,

pressure);
4)
process
stream
composition;
and
5)
costs.
51
4.1.3.1
Pumps.
Pumps
are
used
widely
in
the
petroleum
refining
industry
for
the
movement
of
organic
liquids.
Liquids
transferred
by
pump
can
leak
at
the
point
of
contact
between
the
moving
shaft
and
the
stationary
casing.
Consequently,
all
pumps
require
a
seal
at
the
point
where
the
shaft
penetrates
the
housing
in
order
to
isolate
the
pumped
fluid
from
the
environment.

Two
generic
types
of
seals,
packed
and
mechanical,
are
used
on
pumps.
Packed
seals
can
be
used
on
both
reciprocating
and
rotary
action
(
centrifugal)
pumps.
A
packed
seal
consists
of
a
cavity
(
or
"
stuffing
box")
in
the
pump
casing
filled
with
packing
material
that
is
compressed
with
a
packing
gland
to
form
a
seal
around
the
shaft.
Coolant
is
required
to
remove
the
frictional
heat
between
the
packing
and
shaft.
The
necessary
lubrication
is
provided
by
a
coolant
that
flows
between
the
packing
and
the
shaft.
Deterioration
of
the
packing
can
result
in
leakage
of
the
process
liquid.

Mechanical
seals
are
limited
in
application
to
pumps
with
rotating
shafts.
There
are
single
and
double
mechanical
seals,

with
many
variations
to
their
basic
design,
but
all
have
a
lapped
seal
face
between
a
stationary
element
and
a
rotating
seal
ring.

In
a
single
mechanical
seal,
the
faces
are
held
together
by
the
pressure
applied
by
a
spring
on
the
drive
and
by
the
pump
pressure
transmitted
through
the
pumped
fluid
on
the
pump
end.

An
elastomer
O­
ring
seals
the
rotating
face
to
the
shaft.
The
stationary
face
is
sealed
to
the
stuffing
box
with
another
elastomer
O­
ring
or
gasket.

For
double
mechanical
seals,
two
seals
are
arranged
back­

toback
in
tandem,
or
face
to
face.
In
the
back­
to­
back
arrangement,
a
closed
cavity
is
created
between
the
two
seals.
A
seal
liquid,
such
as
water
or
seal
oil,
is
circulated
through
the
cavity.
This
seal
liquid
is
used
to
control
the
temperature
in
the
stuffing
box.
For
the
seal
to
function
properly,
the
pressure
of
the
seal
liquid
must
be
greater
than
the
operating
pressure
of
the
pump.
In
this
manner,
any
leakage
would
occur
across
the
seal
faces
into
the
process
or
the
environment.
52
Double
mechanical
seals
are
used
in
many
process
applications,

but
there
are
some
conditions
for
which
their
use
is
not
indicated.
Such
conditions
include
service
temperatures
above
260
degrees
Celsius,
and
pumps
with
reciprocating
shaft
motion.

Further,
double
mechanical
seals
cannot
be
used
where
the
process
fluid
contains
slurries,
polymeric,
or
undissolved
solids.

Another
type
of
pump
used
in
the
petroleum
refining
industry
is
the
seal­
less
pump.
Seal­
less
pumps
are
used
primarily
in
processes
where
the
pumped
fluid
is
hazardous,
highly
toxic,
or
very
expensive
and
where
every
effort
must
be
made
to
prevent
all
possible
leakage
of
the
fluid.
Canned­
motor,
diaphragm,
and
magnetic
drive
pumps
are
three
common
types
of
seal­
less
pumps.

Canned­
motor
pumps
have
interconnected
cavity
housings,
motor
rotors,
and
pump
casings.
Because
the
process
liquid
is
the
bearing
lubricant,
abrasive
solids
in
the
process
lines
cannot
be
tolerated.
Canned­
motor
pumps
are
widely
used
for
handling
organic
solvents,
organic
heat
transfer
liquids,
and
light
oils.

Diaphragm
pumps
contain
a
flexible
diaphragm
of
metal,
rubber,

and
plastic
as
the
driving
member.
The
primary
advantage
of
this
arrangement
is
the
elimination
of
all
packing
and
seals
exposed
to
the
process
liquid
provided
the
diaphragm's
integrity
is
maintained.
This
is
important
when
handling
hazardous
or
toxic
liquids.
Emissions
from
diaphragm
pumps
can
be
large,
however,

if
the
diaphragm
fails.
In
magnetic­
drive
pumps,
no
seals
contact
the
process
fluid.
An
externally­
mounted
magnet
coupled
to
the
pump
motor
drives
the
impeller
in
the
pump
casing.

4.1.3.2
Compressors.
Compressors
move
gas
through
a
process
unit
in
much
the
same
way
that
pumps
transport
liquid.

Compressors
are
typically
driven
with
rotating
or
reciprocating
shafts.
Thus,
the
sealing
mechanisms
for
compressors
are
similar
to
those
for
pumps,
i.
e.,
packed
and
mechanical
seals.
Emissions
from
this
source
type
may
be
reduced
by
improving
the
seals'

performance
or
by
collecting
and
controlling
the
emissions
from
the
seal.
Emissions
from
mechanical
contact
seals
depend
on
the
type
of
seal
or
control
device
used
and
the
frequency
of
seal
failure.
53
Shaft
seals
for
compressors
are
of
several
different
types:

labyrinth,
restrictive
carbon
rings,
mechanical
contact,
and
liquid
film.
All
of
these
seal
types
restrict
leaks,
although
none
of
them
completely
eliminates
leakage.
Compressors
can
be
equipped
with
ports
in
the
seal
area
to
evacuate
collected
gases,

which
could
then
be
controlled.

A
buffer
or
barrier
fluid
may
be
used
with
these
mechanical
seals
to
form
a
buffer
between
the
compressed
gas
and
the
environment,
similar
to
barrier
fluids
in
pumps.
This
system
requires
a
clean,
external
gas
supply
that
is
compatible
with
the
gas
being
compressed.
Barrier
gas
can
become
contaminated
and
must
be
disposed
of
properly,
for
example
by
venting
to
a
control
device.
Compressors
can
also
be
equipped
with
liquid
film
seals.

This
seal
is
formed
by
a
film
of
oil
between
the
rotating
shaft
and
stationary
gland.

4.1.3.3
Agitators.
Agitators
are
used
to
stir
or
blend
chemicals.
As
with
pumps
and
compressors,
emissions
from
agitators
can
occur
at
the
interface
of
a
moving
shaft
and
a
stationary
casing.
Emissions
from
this
source
type
may
be
reduced
by
improving
the
seal
or
by
collecting
and
controlling
emissions.
There
are
four
seal
arrangements
commonly
used
with
agitators:
packed
seals,
mechanical
seals,
hydraulic
seals,
and
lip
seals.
Packed
seals
for
agitators
are
similar
in
design
and
application
to
the
packed
seals
for
pumps.

While
mechanical
seals
are
more
costly
than
other
seal
arrangements,
they
provide
better
leakage
rate
reduction.
Also,

the
maintenance
frequency
of
properly
installed
and
maintained
mechanical
seals
is
one­
half
to
one­
fourth
that
of
packed
seals.

Mechanical
seals
can
be
designed
specifically
for
high
pressure
applications
(
i.
e.,
greater
than
1,140
kPa
or
165
psia).
As
with
packed
seals,
the
mechanical
seals
for
agitators
are
similar
to
the
design
and
application
of
mechanical
seals
for
pumps.

The
hydraulic
seal
is
the
simplest
and
least­
used
agitator
shaft
seal.
In
this
type
of
seal,
an
annular
cup
attached
to
the
process
vessel
contains
a
liquid
that
contacts
an
inverted
cup
attached
to
the
rotating
agitator
shaft.
The
primary
advantage
of
this
seal
is
that
it
is
a
noncontact
seal.
However,
this
seal
54
is
limited
to
low
temperatures
and
pressures
and
can
only
handle
very
small
fluctuations.
Process
chemicals
may
contaminate
the
seal
liquid
and
then
be
released
into
the
atmosphere
as
equipment
leak
emissions.

Lip
seals,
which
are
relatively
inexpensive
and
easy
to
install,
can
be
used
on
a
top­
entering
agitator
as
a
dust
or
vapor
seal.
Once
the
seal
has
been
installed,
the
agitator
shaft
rotates
in
continuous
contact
with
the
lip
seal.
Emissions
can
be
released
through
this
seal
when
it
wears
excessively
or
when
the
operating
pressure
surpasses
the
pressure
limitation
of
the
seal.

4.1.3.4
Pressure
Relief
Devices.
Insurance,
safety,
and
engineering
codes
require
that
pressure
relief
devices
or
systems
be
used
in
applications
where
the
process
pressure
may
exceed
the
maximum
allowable
working
pressure
of
the
process
equipment.

Pressure
relief
devices
include
rupture
disks
and
safety/
relief
valves.
The
most
common
pressure
relief
device
is
a
springloaded
valve
designed
to
open
when
the
operating
pressure
of
a
piece
of
process
equipment
exceeds
a
set
pressure.
Equipment
leak
emissions
from
spring­
loaded
relief
valves
may
be
caused
by
failure
of
the
valve
seat
or
valve
stem,
improper
reseating
after
overpressure
relief,
or
process
operation
near
the
relief
valve
set
pressure
which
may
cause
the
relief
valve
to
frequently
open
and
close
or
"
simmer."

Rupture
disks
are
designed
to
burst
at
overpressure
to
allow
the
process
gas
to
vent
directly
to
the
atmosphere.
Rupture
disks
allow
no
emissions
as
long
as
the
integrity
of
the
disk
is
maintained.
They
must
be
replaced
after
each
pressure
relief
episode
to
restore
the
process
to
an
operating
pressure
condition.
Although
rupture
disks
can
be
used
alone,
they
are
sometimes
installed
upstream
of
a
relief
valve
to
prevent
emissions
through
the
relief
valve
stem.

Combinations
of
rupture
disks
and
relief
valves
require
certain
design
constraints
and
criteria
to
avoid
potential
safety
hazards.
For
example,
appropriate
piping
changes
must
be
made
to
prevent
disk
fragments
from
lodging
in
damaging
the
relief
valve
when
relieving
overpressure.
A
block
valve
upstream
of
the
55
rupture
disk
can
be
used
to
isolate
the
rupture
disk/
relief
valve
combination
and
permit
in­
service
replacement
of
the
disk
after
it
bursts.
Otherwise,
emissions
could
result
through
the
relief
valve.

4.1.3.5
Open­
Ended
Lines.
Emissions
from
open­
ended
lines
are
caused
by
leakage
through
the
seat
of
an
upstream
valve
in
the
open­
ended
line.
Emissions
that
occur
through
the
stem
and
gland
of
the
valve
are
not
considered
"
open­
ended"
emissions
and
are
addressed
in
the
section
on
process
valves.
Emissions
from
open­
ended
lines
can
be
controlled
by
installing
a
cap,
plug,

flange,
or
second
valve
to
the
open
end.
Control
efficiency
of
these
control
measures
is
assumed
to
be
100
percent.

4.1.3.6
Sampling
Connections.
Emissions
from
sampling
connections
occur
as
a
result
of
purging
the
sampling
line
to
obtain
a
representative
sample
of
the
process
fluid.
These
emissions
can
be
reduced
by
using
a
closed
loop
sampling
system
or
disposing
of
the
purged
process
fluid
in
a
control
device.

The
closed
loop
sampling
system
is
designed
to
return
the
purged
fluid
to
the
process
at
a
point
of
lower
pressure.
Closed
loop
sampling
is
assumed
to
be
100
percent
effective
for
controlling
emissions
from
a
sample
purge.
This
purged
fluid
could
also
be
directed
to
a
control
device
such
as
an
incinerator,
in
which
case
the
control
efficiency
would
depend
on
the
efficiency
of
the
incinerator
in
removing
the
VOC.

4.1.3.7
Process
Valves.
There
are
many
designs
for
valves,

and
most
of
the
designs
contain
a
valve
stem
which
operates
to
restrict
or
allow
fluid
flow.
Typically,
the
stem
is
sealed
by
a
packing
gland
or
O­
ring
to
prevent
leakage
of
process
fluid
to
the
atmosphere.
Emissions
from
valves
occur
at
the
stem
or
gland
area
of
the
valve
body
when
the
packing
or
O­
ring
in
the
valve
fails.

Valves
that
require
the
stem
to
move
in
and
out
or
turn
must
utilize
a
packing
gland.
A
variety
of
packing
materials
are
suitable
for
conventional
packing
glands.
The
most
common
packing
materials
are
the
various
types
of
braided
asbestos
that
contain
lubricants;
other
packing
materials
include
graphite,

graphite­
impregnated
fibers,
and
tetrafluorethylene.
The
choice
56
of
packing
material
depends
on
the
valve
application
and
configuration.
Conventional
packing
glands
can
be
used
over
a
wide
range
of
operating
temperatures.

Emissions
from
process
valves
can
be
eliminated
if
the
valve
stem
can
be
isolated
from
the
process
fluid.
There
are
two
types
of
sealless
valves
available:
diaphragm
valves
and
sealed
bellows
valves.

Diaphragm
valves
isolate
the
valve
stem
from
the
process
fluid
using
a
flexible
elastomer
or
metal
diaphragm.
The
position
of
the
diaphragm
is
regulated
by
a
plunger,
which
is
controlled
by
the
stem.
Depending
on
the
diaphragm
material,
this
type
of
valve
can
be
used
at
temperatures
as
high
as
205
degrees
Celsius
and
in
strong
acid
service.
If
the
diaphragm
fails,
the
valve
can
become
a
relatively
larger
source
of
emissions.
In
addition,

use
at
temperatures
beyond
the
operating
limits
of
the
material
tends
to
damage
or
destroy
the
diaphragm.

Sealed
bellows
valves
are
another
alternative
leakless
design.

In
this
valve
type,
metal
bellows
are
welded
to
the
bonnet
and
disk
of
the
valve,
thereby
isolating
the
stem
from
the
process.

These
valves
can
be
designed
to
withstand
high
temperatures
and
pressures
and
can
provide
leak­
free
service
at
operating
conditions
beyond
the
limits
of
diaphragm
valves.
However,
they
are
usually
dedicated
to
highly
toxic
services
and
the
nuclear
industry.

The
control
effectiveness
of
both
diaphragm
and
sealed
bellows
valves
is
essentially
100
percent,
although
a
failure
of
the
diaphragm
or
bellows
could
cause
temporary
emissions
much
larger
than
those
from
other
types
of
valves.

4.1.3.8
Connectors.
Connectors
are
flanges,
threaded
fittings,
and
other
fittings
used
to
join
sections
of
piping
and
equipment.
They
are
used
wherever
pipe
or
other
equipment
(
such
as
vessels,
pumps,
valves,
and
heat
exchangers)
require
isolation
or
removal.

Flanges
are
bolted,
gasket­
sealed
connectors.
Normally,

flanges
are
used
for
pipes
with
diameters
of
50
mm
or
greater
and
are
classified
by
pressure
rating
and
face
type.
The
primary
cause
of
flange
leakage
are
poor
installation
and
thermal
stress,
57
which
results
in
the
deformation
of
the
seal
between
the
flange
faces.

Threaded
fittings
are
made
by
cutting
threads
into
the
outside
end
of
one
piece
(
male)
and
the
inside
end
of
another
piece
(
female).
These
male
and
female
parts
are
then
screwed
together
like
a
nut
and
bolt.
Threaded
fittings
are
normally
used
to
connect
piping
and
equipment
having
diameters
of
50
mm
or
less.

Seals
for
these
fittings
are
made
by
coating
the
male
threads
with
a
sealant
before
joining
it
to
the
female
piece.
Emissions
from
threaded
fittings
can
occur
as
the
sealant
ages
and
eventually
cracks.
Leakage
can
also
occur
as
the
result
of
poor
assembly
or
application
of
the
sealant,
and
thermal
stress
of
the
piping
and
fittings.

Emissions
from
connectors
can
be
controlled
by
regularly
scheduled
maintenance.
Potential
emissions
can
be
reduced
by
replacing
the
gasket
or
sealant
materials.
If
connectors
are
not
required
for
process
modification
or
periodic
equipment
removal,

emissions
from
connectors
can
be
eliminated
by
welding
the
connectors
together.

4.1.3.9
Instrumentation
Systems.
An
instrumentation
system
is
a
group
of
equipment
components
used
to
condition
and
convey
a
sample
of
process
fluid
to
analyzers
and
instruments
for
the
purpose
of
determining
process
operating
conditions
(
e.
g.,

composition,
pressure,
and
flow
rate).
Valves
and
connectors
are
the
predominant
types
of
equipment
used
in
instrumentation
systems,
although
other
equipment
may
be
included.
Emissions
resulting
from
the
components
in
the
instrumentation
system
are
controlled
as
they
are
for
the
same
component
in
the
process
system.

Emissions
from
equipment
leaks
may
be
controlled
by
installed
a
closed
vent
system
around
the
leaking
equipment
and
venting
the
emissions
to
a
control
device.
This
method
of
control
is
only
applicable
to
certain
equipment
types,
i.
e.,
pumps,
compressors,

agitators,
pressure
relief
valves,
and
product
accumulator
vessels.
Because
of
the
many
valves,
connectors,
and
open­
ended
lines
typically
found
in
refineries,
it
is
not
practical
to
use
this
technique
for
reducing
emissions
from
all
of
these
potential
58
sources
for
an
entire
process
unit.
However,
a
closed
vent
system
can
be
used
to
control
emissions
from
a
limited
number
of
components,
which
could
be
enclosed
and
maintained
under
negative
pressure
and
vented
to
a
control
device.

LDAR
methods
are
used
to
identify
equipment
components
that
are
emitting
significant
amounts
of
VOC
and
to
reduce
these
emissions.
The
emission
reduction
potential
for
LDAR
as
a
control
technique
is
highly
variable
and
depends
on
several
factors,
the
most
important
of
which
are
the
frequency
of
monitoring
and
the
techniques
used
to
identify
leaks.
Repair
of
leaking
components
is
required
only
when
the
equipment
leak
emissions
reach
a
set
level

the
leak
detection
level.
A
low
leak
definition
will
initiate
repair
at
lower
levels,
resulting
in
a
lower
overall
emission
rate.

Leak
detection
methods
include
individual
component
surveys,

area
(
walk­
through)
surveys,
and
fixed
point
monitors.

Individual
component
surveys
form
a
part
of
the
other
methods.

4.1.3.9.1
Individual
Component
Survey.
Each
source
of
equipment
leak
emissions
(
pump,
valve,
compressor,
etc.)
can
be
checked
for
VOC
leakage
by
visual,
audible,
olfactory,
soap
bubble,
or
instrument
techniques.
Visual
methods
are
good
for
locating
liquid
leaks.
A
visible
leak
does
not
necessarily
indicate
VOC
emissions,
however,
because
the
leaking
material
may
be
non­
VOC.
High­
pressure
leaks
may
be
detected
by
the
sound
of
escaping
vapors,
and
leaks
of
odorous
materials
may
be
detected
by
smell.

Soap
spraying
on
equipment
components
can
be
used
to
survey
individual
components
in
certain
applications.
If
the
soap
solution
forms
bubbles
or
blows
away,
a
leak
is
indicated,
and
vice
versa.
Disadvantages
of
this
method
are
that
1)
it
does
not
distinguish
leaks
of
hazardous
VOCs
from
nonhazardous
VOCs;
2)
it
is
only
semiquantitative,
since
it
requires
the
observer
to
determine
subjectively
the
rate
of
leakage
based
on
the
behavior
of
the
soap
bubbles;
and
3)
it
is
limited
to
sources
with
temperatures
below
100
degrees
Celsius,
because
the
water
in
the
soap
solution
will
evaporate
at
temperatures
above
this
figure.

This
method
is
also
not
suited
for
moving
shafts
on
pumps
or
59
compressors,
because
the
motion
of
the
shaft
may
interfere
with
the
motion
of
the
bubbles
caused
by
a
leak.

The
best
method
for
identifying
leaks
of
VOC
from
components
is
using
a
portable
hydrocarbon
detection
instrument.
Air
close
to
the
potential
leak
site
is
sampled
and
analyzed
by
a
sampling
traverse
("
monitoring")
over
the
entire
are
where
leaks
may
occur.
The
concentration
of
hydrocarbons
in
the
sampled
air
is
displayed
on
the
instrument
meter
and
is
a
rough
indicator
of
the
VOC
emission
rate
from
the
component.
If
the
concentration
is
higher
than
a
specified
figure
("
action
level"),
then
the
leaking
component
is
marked
for
repair.

4.1.3.9.2
Area
Survey.
An
area
or
walk­
through
survey
requires
the
use
of
a
portable
hydrocarbon
detector
and
a
strip
chart
recorder.
The
procedure
involves
carrying
the
instrument
within
one
meter
of
the
upwind
and
downwind
sides
of
process
equipment.
The
instrument
is
then
used
for
an
individual
component
survey
in
a
suspected
leak
area.
The
efficiency
of
this
method
for
locating
leaks
is
not
well
established.
Problems
with
this
method
include
the
fact
that
leaks
from
overhead
valves
or
relief
valves
will
not
be
detected,
and
the
possibility
of
leaks
from
adjacent
units
and
adverse
meteorological
conditions
affecting
the
results
of
the
walk­
through
survey.
Thus,
the
area
survey
is
best
for
locating
only
large
leaks
at
small
expense.

4.1.3.9.3
Fixed
Point
Monitors.
This
method
consists
of
placing
several
automatic
hydrocarbon
sampling
and
analysis
instruments
at
various
locations
in
the
process
unit.
If
elevated
hydrocarbon
concentrations
are
detected,
a
leaking
component
is
indicated.
Identifying
the
specific
leaking
component
requires
an
individual
component
survey.
The
efficiency
of
fixed
point
monitoring
is
not
well
established,
but
fixed
point
monitoring
of
VOCs
is
not
as
effective
as
a
complete
individual
component
survey.
Fixed­
point
monitors
are
expensive,

multiple
units
may
be
required,
and
the
portable
instrument
is
also
needed
to
locate
the
particular
leaking
component.

Calibration
and
maintenance
costs
may
be
high.
Fixed­
point
monitors
are
used
successfully
to
detect
emissions
of
hazardous
or
toxic
substances,
and
can
provide
an
increased
detection
60
efficiency
by
selecting
a
particular
compound
as
the
sampling
criterion.

4.1.3.9.4
Repair
Methods.
This
section
describes
repair
methods
for
possible
equipment
emission
sources
in
a
refinery.

These
are
not
intended
to
be
complete
repair
procedures.

Many
pumps
have
in­
line
or
parallel
spares
that
can
be
used
while
the
leaking
pump
is
being
repaired.
Leaks
from
packed
seals
may
be
reduced
by
tightening
the
packing
gland.
With
mechanical
seals,
the
pump
must
be
dismantled
to
repair
or
replace
the
leaking
seal.
Dismantling
pumps
can
result
in
spillage
of
some
process
fluid.
If
the
seal
leak
is
small,

evaporative
emissions
of
VOC
from
such
spillage
may
be
greater
than
the
continued
leak
from
the
seal.
Precautions
must
be
taken
to
prevent
or
reduce
these
emissions.

Leakage
from
compressors
with
packed
seals
may
be
reduced
by
tightening
the
packing
gland,
as
described
for
pumps.
Repair
of
compressors
with
mechanical
seals
requires
the
compressor
be
removed
from
service.
Since
compressors
usually
do
not
have
spares,
immediate
repair
may
not
be
practical
or
possible
without
a
process
unit
shutdown.

Agitators,
like
pumps
and
compressors,
can
leak
VOCs
at
the
point
where
the
shaft
penetrates
the
casing,
and
seals
are
required
to
minimize
fugitive
emissions.
Leaks
from
packed
seals
may
be
reduced
by
the
repair
procedure
described
for
pumps,
while
repair
of
other
types
of
seals
require
the
agitator
to
be
out
of
service.
In
this
latter
case,
process
shutdown
or
isolation
of
the
particular
agitator
being
repaired
is
required.

Leaking
repair
valves
usually
must
be
removed
for
repair.
To
remove
the
relief
valve
without
shutting
down
the
process,
a
block
valve
may
be
required
upstream
of
the
relief
valve.
A
spare
relief
valve
should
be
attached
while
the
faulty
valve
is
repaired
and
tested.

A
rupture
disk
can
be
installed
upstream
from
a
pressure
relief
valve
to
eliminate
leaks
until
an
overpressure
release
occurs.
Once
a
release
occurs,
the
rupture
disk
must
be
replaced
to
prevent
further
leaks.
A
block
valve
is
required
to
isolate
the
rupture
disk
for
replacement.
61
Most
valves
have
a
packing
gland
that
can
be
tightened
while
in
service.
Although
this
procedure
should
decrease
the
emissions
from
the
valve,
it
can
actually
increase
the
emission
rate
if
the
packing
is
old
and
brittle
or
has
been
overtightened
Some
types
of
valves
have
no
means
of
in­
service
repair
and
must
be
isolated
from
the
process
and
removed
for
repair
and
replacement.
Most
control
valves
have
a
manual
bypass
loop
that
allows
them
to
be
isolated
and
removed.
Most
block
valves
cannot
be
isolated
easily,
although
temporary
changes
in
process
operation
may
allow
isolation
in
some
cases.

In
some
cases,
leaks
from
connectors
can
be
reduced
by
replacing
the
connector
gaskets,
but
most
connectors
cannot
be
isolated
to
permit
gasket
replacement.
Tightening
of
connector
bolts
also
may
reduce
emissions
from
connectors.
Where
connectors
are
not
required
for
process
modification
or
periodic
equipment
removal,
emissions
from
connectors
can
be
eliminated
by
welding
them.

4.1.4
Internal
Floating
Roofs
Internal
floating
roofs
are
commonly
used
in
the
petroleum
refining
industry
to
control
emissions
from
fixed­
roof
storage
tanks.
As
the
name
implies,
it
is
a
roof
inside
a
tank
that
floats
on
the
surface
of
the
stored
liquid.

The
presence
of
a
floating
roof
(
or
deck)
inside
a
fixed
roof
tank
significantly
reduces
the
surface
area
of
exposed
liquid.

It
serves
as
a
physical
barrier
between
the
volatile
organic
liquid
and
the
air
that
enters
the
tank
through
vents.

Because
evaporation
is
the
primary
emission
mechanism
associated
with
storage
tanks,
emissions
from
floating
roof
tanks
as
well
as
fixed
roof
tanks
vary
with
the
vapor
pressure
of
the
stored
liquid.
Thus,
the
control
efficiency
of
retrofitting
a
fixed
roof
tank
with
an
internal
floating
deck
depends
on
the
material
being
stored.

Other
factors
affecting
emissions,
and
therefore
control
efficiency,
are
tank
size,
number
of
turnovers,
and
the
type
of
deck
and
seal
system
selected.
Installing
an
internal
floating
roof
can
reduce
emissions
by
61
to
98
percent.
The
relative
62
effectiveness
of
one
internal
floating
roof
design
over
another
is
a
function
of
how
well
the
deck
can
be
sealed.
Probably
the
most
typical
internal
floating
roof
design
is
the
noncontact,

bolted,
aluminum
internal
floating
roof
with
a
single
vapormounted
wiper
seal
and
uncontrolled
fittings.

Loss
of
VOCs
from
internal
floating
roof
tanks
occurs
in
one
of
four
ways:

1)
Through
the
annular
rim
space
around
the
perimeter
of
the
floating
roof
(
seal
losses),

2)
Through
the
openings
in
the
deck
required
for
various
types
of
fittings
(
fitting
losses),

3)
Through
the
nonwelded
seams
formed
when
joining
sections
of
the
deck
material
(
deck
seam
losses),
and
4)
Through
evaporation
of
liquid
left
on
the
tank
wall
following
withdrawal
of
liquid
from
the
tank
(
withdrawal
loss).

4.1.4.1
Control
of
Seal
Losses.
Internal
floating
roof
seal
losses
can
be
minimized
by
employing
liquid­
mounted
primary
seals
instead
of
vapor­
mounted
seals
and/
or
by
employing
secondary
wiper
seals
in
addition
to
primary
seals.

Available
emissions
test
data
suggest
that
the
location
of
the
seal
(
i.
e.,
vapor­
or
liquid­
mounted)
and
the
presence
of
a
secondary
seal
are
the
major
factors
affecting
seal
losses.
A
liquid­
mounted
primary
seal
has
a
lower
emissions
rate,
and
thus
a
higher
control
efficiency,
than
a
vapor­
mounted
seal.
A
secondary
seal,
with
either
a
liquid­
or
a
vapor­
mounted
primary
seal,
provides
an
additional
level
of
control.

The
type
of
seal
used
plays
a
less
significant
role
in
determining
the
emissions
rate.
The
type
of
seal
is
important
only
to
the
extent
that
the
seal
must
be
suitable
for
the
particular
application.
For
instance,
an
elastomeric
wiper
seal
is
commonly
employed
as
a
vapor­
mounted
primary
seal
or
as
a
secondary
seal
for
an
internal
floating
roof.
Because
of
its
shape,
this
seal
is
not
suitable
for
use
as
a
liquid­
mounted
primary
seal.
Resilient
foam
seals,
on
the
other
hand,
can
be
used
as
both
liquid­
and
vapor­
mounted
seals.
63
4.1.4.2
Control
of
Fitting
Losses.
There
are
numerous
fittings
that
penetrate
or
are
attached
to
an
internal
floating
roof.
Among
them
are
access
hatches,
column
wells,
roof
legs,

sample
pipes,
ladder
wells,
vacuum
breakers,
and
automatic
gauge
float
wells.
Fitting
losses
occur
when
VOCs
leak
around
these
fittings.
Fitting
losses
can
be
controlled
with
gasketing
and
sealing
techniques
or
by
the
substitution
of
fittings
that
are
designed
to
leak
less.

The
effectiveness
of
fitting
controls
at
reducing
the
overall
emission
rate
is
a
function
of
the
number
of
fittings
of
each
type
employed
on
a
given
tank.
For
example,
if
using
controlled
fittings
reduces
total
fitting
loss
by
36
percent,
and
if
fitting
losses
are
about
35
percent
of
the
total
emissions
from
a
typical
internal
floating
roof
tank,
then
the
controlled
fittings
reduce
the
overall
emissions
by
(.
36*.
35)=
.126,
or
12.6
percent
over
a
similar
tank
without
fitting
controls.
The
usual
increase
in
control
efficiency
achieved
by
installing
controlled
fittings
ranges
from
0.5
to
1.0
percent.

4.1.4.3
Control
of
Deck
Seam
Losses.
Deck
seam
losses
are
inherent
in
a
number
of
floating
roof
types
including
internal
floating
roofs.
Any
roof
constructed
of
sheets
or
panels
fastened
by
mechanical
fasteners
(
e.
g.,
bolts)
is
expected
to
have
deck
seam
losses.
Deck
seam
losses
are
considered
to
be
a
function
of
the
length
of
the
seams
and
not
the
type
of
mechanical
fastener
or
the
position
of
the
deck
relative
to
the
liquid
surface.
This
is
a
conclusion
drawn
from
a
1986
study
on
two
roof
types
with
significantly
different
mechanical
fasteners
and
differences
in
the
amount
of
contact
with
the
liquid
surface.

Deck
seam
losses
are
controlled
by
selecting
a
roof
type
with
vapor­
tight
deck
seams.
The
welded
deck
seams
on
steel
pan
roofs
are
vapor
tight.
Fiberglass
lapped
seams
of
a
glass
fiber
reinforced
polyester
roof
may
be
vapor
tight
as
long
as
there
is
negligible
permeability
of
the
liquid
through
the
seam
lapping
materials.
Some
manufacturers
provide
gaskets
for
bolted
metal
deck
seams.

Selecting
a
welded
roof
(
rather
than
a
bolted
roof)
will
eliminate
deck
seam
losses.
For
a
typical
internal
roof
that
has
64
primary
seals,
secondary
seals,
and
controlled
fittings
already,

eliminating
deck
seam
losses
will
raise
the
control
efficiency
as
much
as
1.5
percent.

4.1.4.4
Applicability.
The
applicability
of
any
storage
tank
improvement
in
order
to
reduce
VOC
emissions
is
dependent
upon
the
characteristics
of
the
particular
VOC.
Since
floating
decks
are
often
constructed
primarily
of
aluminum,
they
may
not
be
applicable
to
tanks
storing
halogenated
compounds,
pesticides,
or
other
compounds
that
are
incompatible
with
aluminum.
Contact
between
these
compounds
and
an
aluminum
deck
could
corrode
the
deck
and
cause
product
contamination.

In
addition,
vapor
pressures
may
affect
the
selection
of
tank
improvements
as
an
applicable
control
technology.
For
chemicals
with
very
low
vapor
pressure,
fixed
roof
tank
emissions
will
already
be
so
low
that
installing
an
internal
floating
roof
may
not
significantly
reduce
emissions
further.
For
chemicals
with
vapor
pressures
up
to
65
kPa
(
9.4
psia),
emission
reductions
of
95
percent
and
above
are
achievable
with
this
technology.
Above
this
vapor
pressure,
achievable
emission
reduction
starts
to
decrease
with
increasing
vapor
pressure.
Thus,
an
internal
floating
roof
may
not
be
indicated
for
chemicals
with
relatively
high
vapor
pressures.
1
4.2
DESCRIPTION
OF
MACT
AND
SUMMARY
OF
REGULATORY
ALTERNATIVES
The
CAA
requires
that
in
designating
regulatory
options,
the
maximum
degree
of
reduction
in
emissions
that
is
deemed
achievable
shall
be
subject
to
a
floor,
which
is
determined
differently
for
new
and
existing
sources.
For
new
sources,
the
standards
must
be
set
at
levels
which
are
not
any
less
stringent
than
the
emission
control
that
is
achieved
in
practice
by
the
best
controlled
similar
source.
For
existing
sources,
the
standards
may
not
be
less
stringent
than
the
average
emission
limitation
achieved
by
the
best
performing
12
percent
of
existing
sources
in
each
category
or
subcategory
of
30
or
more
sources.

In
determining
whether
the
standard
should
be
more
stringent
than
the
floor
and
by
how
much,
EPA
is
to
consider,
among
other
65
things,
the
cost
of
achieving
such
additional
emission
reductions.
The
options
for
achieving
reductions
at
each
emission
point
are
presented
separately
in
the
following
sections.
The
chosen
option
and
any
more
stringent
options
are
presented
separately
for
each
of
the
four
emission
points.

4.2.1
Miscellaneous
Process
Vents
This
section
summarizes
the
MACT
floors
and
chosen
alternatives
as
they
relate
to
miscellaneous
process
vents
and
how
they
were
arrived
at.
The
EPA
evaluated
the
current
level
of
control
for
miscellaneous
process
vents
in
eight
State
and
two
air
districts
that
contain
the
majority
of
refineries
and
were
expected
to
have
the
most
stringent
regulations.
Of
the
refineries
in
the
U.
S.,
the
12
percent
that
are
subject
to
the
most
stringent
regulations
are
located
in
three
States.
In
these
three
States,
miscellaneous
process
vents
emitting
greater
than
15
to
100
lb/
day
(
6.8
to
44.4
kg/
day)
of
VOC
are
required
to
be
controlled.
The
median
applicability
cutoff
level
for
the
12
percent
of
U.
S.
refineries
subject
to
the
most
stringent
regulations
is
72
lb/
day
(
33
kg/
day)
VOC.
Thus,
control
of
process
vents
with
VOC
emissions
greater
than
72
lb/
day
is
the
MACT
floor
level
of
control
for
existing
sources
and
is
the
standard
for
miscellaneous
process
vents.
The
primary
organic
HAPs
at
refineries
are
also
VOC.
Additionally,
a
VOC­
based
applicability
criteria
is
most
reflective
of
the
current
level
of
control
required
for
miscellaneous
process
vents
as
the
majority
of
State
regulations
are
expressed
in
terms
of
VOC.
Therefore,

the
EPA
has
adopted
this
emission
level
in
the
final
rule
to
distinguish
Group
1
from
Group
2
vents.
Group
1
vents,
those
that
emit
over
33
kg/
day,
must
be
controlled,
whereas
Group
2
vents,
representing
all
other
vents,
are
not
required
to
apply
controls
under
the
final
rule.
The
applicability
limit
is
determined
as
gases
exit
from
process
unit
equipment
and
not
downstream
from
an
emission
control
device.
The
new
source
MACT
floor
also
includes
reduction
of
emissions
from
miscellaneous
process
vents
with
the
same
cut­
off.
66
4.2.2
Storage
Vessels
This
section
summarizes
the
MACT
floors
and
chosen
alternatives
for
storage
vessels.
The
information
that
EPA
used
in
determining
the
floor
level
of
control
for
existing
storage
vessels
consisted
of
the
types
of
storage
vessels,
vessel
capacities,
existing
controls
on
vessels,
and
true
vapor
pressures
of
stored
liquids
reported
by
refineries
responding
to
survey
questionnaires.
EPA
compared
the
baseline
level
of
control
on
each
storage
vessel
at
each
refinery
with
the
storage
vessel
control
requirements
(
with
the
exception
of
fitting
requirements
for
floating
roof
vessels)
of
subpart
Kb
of
40
CFR
60.
Subpart
Kb
represents
the
best
control
technology
for
storage
vessels.
It
requires
either
floating
roofs
with
specified
seals
and
fittings
or
closed
vent
systems
and
control
devices.

Once
the
best
performing
12
percent
were
identified,
the
average
true
vapor
pressure
of
the
stored
liquids
being
controlled
at
these
refineries
was
determined.
The
MACT
floor
level
of
control
for
existing
sources
is:
vessels
with
capacities
greater
than
or
equal
to
177
cubic
meters
(
1,115
barrels
or
47,000
gallons)
storing
liquids
with
true
vapor
pressures
greater
than
or
equal
to
23
kilopascals
(
kPa)

(
3.4
psia)
must
be
controlled
to
the
requirements
of
subpart
Kb
with
the
exception
of
the
controlled
fitting
requirements
for
floating
roof
vessels.
EPA
determined,
based
on
the
available
data,
that
an
emission
reduction
more
stringent
than
the
level
associated
with
the
floor
is
not
cost
effective.

To
determine
the
MACT
floor
for
storage
vessels
at
new
sources,
EPA
reviewed
other
State
and
Federal
storage
vessel
regulations.
The
MACT
floor
and
an
option
more
stringent
than
the
floor
requiring
control
of
storage
vessels
with
vapor
pressures
above
0.014
kPa
(
0.002
psia)
(
which
is
the
same
as
option
3
for
existing
sources)
was
also
considered.
The
level
of
control
for
new
sources
is
the
MACT
floor.
Vessels
with
capacities
greater
than
or
equal
to
151
m3
(
950
barrels
or
40,000
gallons)
storing
liquids
with
true
vapor
pressures
greater
than
or
equal
to
3.4
kPa
(
0.5
psia),
and
vessels
with
capacities
67
greater
than
or
equal
to
76
m3
(
475
barrels
or
20,000
gallons)

storing
liquids
with
vapor
pressures
equal
to
or
greater
than
77
kPa
(
11.1
psia)
would
be
required
to
comply
with
the
subpart
Kb
(
including
the
controlled
fitting
requirements).
The
option
more
stringent
than
the
floor
was
not
selected
because
it
would
result
in
high
costs
relative
to
HAP
emission
reductions.

4.2.3
Wastewater
Streams
This
section
summarizes
the
MACT
floors
and
chosen
alternatives
for
wastewater
streams.
The
alternative
selected
is
the
floor
level
of
control
(
compliance
with
the
Benzene
Waste
Operations
NESHAP
(
BWON)).
The
BWON
controls
75
percent
of
the
benzene
in
refinery
wastewater
and
76
percent
of
the
volatile
organic
HAP
in
refinery
wastewater.
The
best
performing
wastewater
control
systems
are
those
that
are
in
place
to
comply
with
the
BWON.
These
systems
control
not
only
benzene,
but
also
the
other
organic
HAPs
in
petroleum
refinery
wastewater.
The
BWON
controls
75
percent
of
the
benzene
in
refinery
wastewater
nationwide
and
76
percent
of
the
volatile
organic
HAP
in
refinery
wastewater.
Benzene
is
an
effective
surrogate
for
indicating
the
presence
of
all
HAP
compounds
in
petroleum
refinery
wastewater
because
data
show
that
the
majority
of
the
total
HAP
compound
loading
in
wastewater
consists
of
compounds
that
are
very
similar
to
benzene
in
terms
of
both
chemical
structure
and
volatility
(
from
the
water
phase
to
the
air
phase).

Because
the
final
standard
for
wastewater
requires
compliance
with
the
existing
BWON,
no
additional
emission
reduction,
cost,

energy,
or
other
environmental
or
health
impacts
are
associated
with
the
standard.
Based
on
data
provided
to
the
EPA
through
the
BWON
90­
day
reports,
the
EPA
determined
that
the
BWON
was
applicable
to
43
percent
of
the
refineries.
No
refineries
are
known
to
have
more
stringent
controls
than
the
BWON.
Therefore,

the
MACT
floor,
or
the
average
of
the
top
performing
12
percent
of
sources,
is
control
to
the
BWON
level
of
control.

EPA
also
considered
an
alternative
level
of
emission
reduction
more
stringent
than
the
MACT
floor
that
would
be
achieved
by
controlling
all
wastewater
streams
with
at
least
10
ppmw
benzene
68
at
any
refinery
regardless
of
the
size
of
its
annual
benzene
loading.
This
alternative
control
option
was
not
selected
because
the
additional
emission
reduction
achieved
through
further
control
was
not
significant,
given
the
associated
costs.

The
floor
alternative
was
selected
as
the
promulgated
level
of
control
for
new
sources.
As
with
existing
sources,
the
option
more
stringent
than
the
floor
was
considered,
but
was
rejected
for
new
sources
for
the
same
reason
described
above
for
existing
sources.

4.2.4
Equipment
Leaks
The
section
summarizes
the
MACT
floors
and
chosen
alternatives
for
equipment
leaks.
The
Petroleum
Refinery
NSPS
requirements
(
40
CFR
part
60
subpart
VV)
is
the
MACT
floor
for
existing
sources.
In
the
final
rule,
EPA
is
providing
each
existing
refinery
with
a
choice
of
complying
with
either:
1)
The
Petroleum
Refinery
NSPS
equipment
leak
requirements
mentioned
above
or
2)
a
modified
verison
of
the
negotiated
rule
(
40
CFR
part
63
subpart
H).
The
modified
negotiated
regulation
is
the
same
as
what
was
contained
in
the
proposed
petroleum
refinery
NESHAP,
except
that
the
compliance
dates
have
been
extended.

Although
not
required
in
the
final
rule,
the
EPA
promotes
use
of
the
modified
negotiated
rule
option
because
it
is
believed
to
provide
considerable
product,
emissions,
and
cost
savings
to
a
refinery.

Under
either
option,
existing
refineries
will
be
required
to
implement
an
LDAR
program
with
the
same
leak
definitions
(
10,000
ppm)
and
the
same
leak
frequencies
as
contained
in
the
NSPS
by
3
years
after
promulgation.
A
refinery
may
opt
to
remain
at
this
level
of
control
and
do
the
monitoring,
recordkeeping,
and
reporting
specified
in
the
NSPS.
This
option
allows
refineries
that
are
familiar
with
the
Petroleum
Refinery
NSPS
to
continue
to
implement
that
standard
without
needing
to
change
their
procedures.

Alternatively,
a
refinery
may
choose
to
comply
with
Phase
I
of
the
negotiated
rule
(
10,000
ppm
leak
definition)
3
years
after
promulgation,
comply
with
Phase
II
4
years
after
promulgation,
69
and
comply
with
Phase
III
5
1/
2
years
after
promulgation.
Each
phase
has
lower
leak
definitions
for
pumps
and
valves.

For
new
sources,
EPA
requires
refinery
sources
to
meet
the
same
requirements
as
for
existing
sources.

4.2.5
Summary
of
Alternatives
Based
on
the
determination
of
the
MACT
floor
for
each
of
the
four
emission
points,
EPA
selected
a
regulatory
alternative.

Alternative
1,
the
regulatory
alternative
selected,
incorporates
MACT
floor
level
control
for
wastewater
streams,
storage
vessels,

and
miscellaneous
process
vents,
and
the
floor
for
equipment
leaks.
Table
4­
1
presents
a
summary
of
the
alternative
examined
in
this
analysis.

4.3
NO
ADDITIONAL
EPA
REGULATION
E.
O.
12866
requires
that
the
rationale
for
regulation
versus
no
regulation
must
be
addressed
in
the
decision
process.
To
satisfy
this
requirement,
this
section
presents
the
alternatives
to
regulation
of
HAP
emissions
from
petroleum
refineries.
The
alternatives
include
reliance
on
the
judicial
system
for
pollution
control,
or
reliance
on
regulation
by
States
and
localities.

4.3.1
Judicial
System
In
the
absence
of
governmental
regulation,
market
systems
fail
to
make
the
generators
of
pollution
pay
for
the
costs
associated
with
that
pollution.
For
an
individual
firm,
pollution
is
an
apparently
unusable
by­
product
that
can
be
disposed
of
cheaply
by
venting
it
to
the
atmosphere.
However,
in
the
atmosphere,

pollution
causes
real
costs
to
others.
The
fact
that
producers,

consumers,
and
others
whose
activities
result
in
air
pollution
do
not
bear
the
full
costs
of
their
actions
leads
to
a
divergence
between
private
costs
and
social
costs.
This
divergence
is
considered
a
market
failure,
since
it
results
in
a
misallocation
of
society's
resources.
Too
many
resources
are
devoted
to
the
polluting
activity
when
polluters
do
not
bear
the
full
cost
of
their
actions.
TABLE
4­
1.
SUMMARY
OF
REGULATORY
ALTERNATIVES
BY
EMISSION
POINT
Emission
Point
Alternati
ve
1
Description
of
Control
Option
Equipment
Leaks
Option
1
Floor
=
Compliance
with
the
petroleum
refinery
NSPS.
Option
1
=
Compliance
with
provisions
in
40
CFR
part
60
subpart
VV
of
the
Petroleum
Refinery
NSPS,
or
complying
with
a
modified
negotiated
regulation
for
equipment
leaks
presented
in
40
CFR
part
63
subpart
H
(
HON
equipment
leaks).

Miscellaneous
Vents
MACT
Floor
Floor
=
Control
to
20
ppmv
of
organic
HAP
or
98
percent
reduction
of
HAP,
or
to
reduce
emissions
using
a
flare
meeting
the
requirements
of
section
63.11(
b)
of
the
NESHAP
General
Provisions
(
40
CFR
part
63
subpart
A),
for
Group
1
vents
only.

Wastewater
Streams
MACT
Floor
Floor
=
Compliance
with
the
BWON,
only
for
Group
1
streams.

Storage
Vessels
MACT
Floor
Floor
=
Group
1
storage
vessels
only
are
required
to
put
on
one
of
the
following
control
systems:
1)
an
internal
floating
roof
(
IFR)
with
proper
seals;
2)
an
external
floating
roof
(
EFR)

with
proper
seals;
3)
an
EFR
converted
to
an
IFR
with
proper
seals;
or
4)
a
closed
vent
system
with
a
95
percent
efficient
control
device.
71
Also,
if
there
was
no
regulation,
the
previous
regulations
would
be
relied
upon
as
the
basis
for
making
judicial
decisions
regarding
excess
emissions.

4.3.2
State
and
Local
Action
The
CAA
requires
each
State
to
develop
and
implement
measures
to
attain
and
maintain
EPA's
standards.
Each
State
assembles
these
measures
in
a
document
called
the
State
Implementation
Plan
(
SIP).
SIPs
must
be
approved
by
EPA,
and
EPA
is
empowered
to
compel
revision
of
plans
it
believes
are
inadequate.
EPA
may
assume
enforcement
authority
over
air
pollution
control
programs
any
State
fails
to
implement.
The
standards
will
become
parts
of
each
State's
SIP,
and
enforcement
authority
will
be
delegated
to
the
States.
If
the
EPA
were
not
to
promulgate
the
standards,

States
would
be
responsible
for
making
case­
by
case
MACT
decisions
under
Section
112
(
g)
and
(
j)
whenever
there
is
a
major
modification,
or
when
the
date
for
MACT
promulgation
has
passed
without
action
on
EPA's
part.

EPA
believes
that
reliance
on
State
and
local
action
is
not
a
viable
substitute
for
the
standards.
This
belief
holds
even
if
EPA
were
to
step
up
research
and
technology
transfer
programs
to
assist
State
and
local
governments.

4.4
ROLE
OF
COST
EFFECTIVENESS
IN
CHOOSING
AMONG
REGULATORY
ALTERNATIVES
EPA
has
often
used
cost
effectiveness
(
C/
E)
analysis
as
a
guide
for
selecting
among
regulatory
alternatives.
Regulatory
alternatives
can
sometimes
be
ranked
based
on
stringency
of
control.
All
else
equal,
alternatives
yielding
the
same
level
of
control
but
higher
average
C/
E
(
usually
control
cost
per
ton
of
pollutant
reduced)
could
be
eliminated
from
consideration.

Incremental
C/
E
can
then
be
calculated
for
each
step
up
the
stringency
ranking.
The
selection
of
a
regulatory
alternative
could
then
be
made
by
choosing
the
most
stringent
alternative
below
some
agreed
upon
C/
E
cutoff.
The
level
of
such
a
C/
E
72
cutoff
would
generally
depend
on
the
pollutant
being
controlled
and
other
factors.

However,
since
the
Petroleum
Refinery
NESHAP
is
to
be
a
MACT
standard,
the
role
of
C/
E
analysis
for
selecting
a
regulatory
alternative
for
this
regulation
is
somewhat
limited.
A
MACT
floor
level
of
control
stringency
is
required
regardless
of
the
C/
E
at
this
control
level.
At
stringency
levels
beyond
the
MACT
floor,
cost
effectiveness
can
be
legally
considered,
and
EPA
believes
cost­
effectiveness
of
controls
is
a
primary
consideration
for
evaluating
stringency
levels
beyond
the
MACT
floor.
The
average
cost
effectiveness
of
the
regulation
($/
Mg
of
pollutant
removed)
is
included
as
part
of
the
cost
analysis
in
Chapter
5.

4.5
ECONOMIC
INCENTIVES:
SUBSIDIES,
FEES,
AND
MARKETABLE
PERMITS
Economic
incentive
strategies,
when
designed
properly,
act
to
harness
the
marketplace
to
work
for
the
environment.
In
deciding
among
regulatory
options,
EPA
is
required
to
consider
as
options
such
strategies
which
influence,
rather
than
dictate,
producer
and
consumer
behavior,
in
order
to
achieve
environmental
goals.

Economic
incentive
programs
make
environmental
protection
of
economic
interest
to
producers
and
consumers.
When
feasible,

properly
designed
systems
can
be
employed
to
achieve
any
environmental
goal
at
the
least
cost
to
society.

Several
types
or
categories
of
economic
incentive
strategies
exist.
One
broad
category
of
incentive
programs
is
based
of
the
use
of
fees
or
subsidies.
Fee
programs
establish
and
collect
a
fee
on
emissions,
providing
a
direct
economic
incentive
for
emitters
to
decrease
emissions
to
the
point
where
the
cost
of
abating
emissions
equals
the
fee.
3
Similarly,
subsidy
programs
provide
a
direct
incentive
for
emitters
to
decrease
emissions
by
providing
subsidy
payments
for
emission
reductions
beyond
some
baseline.

A
second
broad
category
of
economic
incentive
strategies
is
based
on
the
concept
of
emissions
trading.
A
wide
range
of
73
variations
in
emissions
trading
programs
are
possible.
The
common
idea
in
such
programs
is
to
allow
sources
with
low
abatement
cost
alternatives
to
trade
or
sell
emission
allowances
to
sources
with
higher
abatement
cost
alternatives
so
that
the
cost
of
meeting
a
given
total
level
of
abatement
is
minimized.

There
are
two
important
constraints
regarding
the
workability
of
economic
incentive
programs.
The
first
constraint
concerns
the
problem
of
emissions
monitoring.
Without
an
effective
emissions
monitoring
system
it
is
not
possible
to
charge
fees
or
use
other
economic
incentive
strategies.
Only
the
traditional
"
command
and
control"
approach
of
requiring
employment
of
specific
control
technologies
is
feasible
in
this
circumstance.

The
second
problem
constraining
the
potential
value
of
economic
incentive
strategies
is
legal.
Various
legal
restrictions
imposed
by
the
CAA
limit
the
applicability
of
economic
incentive
strategies
to
reduce
air
pollution.

Legal
constraints
imposed
by
Title
III
of
the
Act
severely
limit
the
usefulness
of
economic
incentive
strategies
for
reducing
HAP
emissions.
Title
III
requires
the
implementation
of
MACT.
Thus
sources
have
little
or
no
choice
as
to
the
type
or
level
of
control
they
implement
except
perhaps
if
going
beyond
the
MACT
floor
control
level.
As
a
limited
economic
incentive,

it
may
then
be
possible
to
impose,
for
example,
an
emissions
fee
on
residual
emissions
after
the
MACT
technology
is
employed
to
encourage
additional
control.

The
applicability
of
economic
incentive
programs
for
the
petroleum
refinery
NESHAP
is
therefore
very
limited.
However,

emissions
averaging
at
the
facility
level
may
be
feasible
and
legal
given
that
each
facility
is
considered
an
emissions
source.

This
emissions
averaging
strategy
allows
facilities
to
trade
emission
reductions
across
emission
points
so
as
to
minimize
control
costs
for
any
given
facility
level
emission
reduction
requirement.
Thus,
to
this
extent,
an
economic
incentive
strategy
may
be
implemented
for
the
Petroleum
Refinery
NESHAP
regulation.
The
analysis
of
control
costs
(
Chapter
5)
does
not
incorporate
emission
averaging.
It
is
recognized
that
if
emissions
averaging
were
incorporated
into
the
standard,
74
facilities'
costs
of
control
should
fall.
Thus,
the
costs
calculated
could
be
an
overestimate.
75
REFERENCES
1.
U.
S.
Environmental
Protection
Agency.
Regulatory
Impact
Analysis
for
the
National
Emissions
Standards
for
Hazardous
Air
Pollutants
for
Source
Categories:
Organic
Hazardous
Air
Pollutants
from
the
Synthetic
Organic
Chemical
Manufacturing
Industry
and
Seven
Other
Processes.
EPA­
450/
3­
92­
009.
pp.
4­
1
to
4­
41.
December
1992.

2.
U.
S.
Environmental
Protection
Agency.
Office
of
Air
Quality
Planning
and
Standards.
Draft
Preamble
for
the
HON.
December
1993.

3.
U.
S.
Environmental
Protection
Agency.
Office
of
Air
Quality
Planning
and
Standards.
Draft
Preamble
for
the
Petroleum
Refinery
NESHAP.
January
1994.

4.
Reference
2.

5.
U.
S.
Environmental
Protection
Agency.
Office
of
Air
Quality
Planning
and
Standards.
Municipal
Waste
Landfills
­
Regulatory
Impact
Analysis.
March
1991.
76
77
5.0
COST
ANALYSIS
AND
EMISSION
REDUCTION
Section
5.1
of
this
chapter
presents
the
methodology
used
to
estimate
the
regulatory
compliance
costs
for
the
option
listed
in
Table
4­
1.
Section
5.2
presents
total
compliance
costs
by
emission
point,
the
corresponding
emission
reductions
for
each
alternative,
and
discusses
the
cost
effectiveness
of
controlling
each
of
the
four
petroleum
refinery
emission
points.
Section
5.4
presents
any
cost
categories
not
directly
associated
with
a
control
technique,
including
monitoring,
reporting,
and
recordkeeping
costs.

5.1
APPROACH
FOR
ESTIMATING
REGULATORY
COMPLIANCE
COSTS
This
section
explains
the
methods
used
for
estimating
the
emissions
associated
with
petroleum
refineries
and
the
impact
associated
with
controlling
existing
petroleum
refinery
emission
sources
using
various
alternative
control
technologies.
These
estimates
are
used
to
compare
different
control
alternatives
and
select
the
provisions
for
the
proposed
NESHAP
for
petroleum
refineries.

Emissions
and
control
impacts
were
estimated
for
each
of
the
four
petroleum
refinery
emission
points:
storage
vessels,

wastewater
collection
and
treatment
systems,
equipment
leaks,
and
miscellaneous
process
vents.
The
control
impact
estimates
include
estimates
of
emission
reductions,
control
costs,
and
where
applicable,
energy
impact.
A
qualitative
assessment
of
the
possible
impact
of
secondary
air
pollution,
water
pollution,
or
solid
waste
generation
is
also
included.

The
emissions
calculations
involved
three
steps:

(
1)
development
of
a
database
characterizing
refineries,

(
2)
development
and
assignment
of
scaling
factors
for
each
kind
78
of
emission
point
to
use
for
estimating
emissions
for
refineries
that
provided
no
data,
and
(
3)
calculation
of
nationwide
emissions
and
control
impacts.

The
database
included
the
processes
and
technology
used
to
produce
refinery
products
and
controls
used
to
reduce
emissions.

This
information
came
from
responses
to
survey
questionnaires
sent
out
under
section
114
of
the
CAA
and
information
collection
requests.
Refineries
across
the
United
States
responded
to
the
questionnaires
and
provided
control
and
process
information
for
process
vents,
storage
vessels,
wastewater
treatment
systems,
and
leaking
equipment.
In
addition,
information
on
existing
regulations
was
compiled
to
determine
the
control
requirements
that
apply
to
petroleum
refineries.

Because
site­
specific
data
were
not
available
for
every
refinery,
scaling
factors
relating
refinery
process
parameters
or
emissions
to
the
charge
capacity
of
refinery
processes
were
derived
from
the
available
data.
Estimates
of
emissions
and
control
impacts
for
refineries
for
which
data
were
lacking
were
derived
using
scaling
factors.
Scaling
factors
could
be
used
because
the
emission
mechanisms
and
applicable
control
technologies
are
well
understood
for
the
kinds
of
sources
to
be
regulated
by
the
petroleum
refinery
NESHAP,
and
these
characteristics
are
similar
from
refinery
to
refinery.

Baseline
emissions
represent
emission
levels
from
petroleum
refineries
that
would
occur
in
the
absence
of
a
refinery
MACT
standard.
Baseline
emissions
were
estimated
using
calculation
algorithms
based
on
known,
previously
published,
well­
established
methods
from
the
process
charge
capacities
of
the
refineries
in
the
database
and
the
data
reported
in
the
questionnaire
responses.
The
impact
of
each
alternative
control
level
was
estimated
using
previously
developed
cost
algorithms
and
control
efficiencies
for
commonly
used
control
technologies.
The
control
technologies
included
in
the
analysis
were
chosen
because
they
can
achieve
emission
reductions
at
least
as
stringent
as
the
MACT
floor.
While
the
selected
control
technologies
were
used
as
the
basis
of
the
control
impacts
estimates,
the
promulgated
standards
79
are
written
using
formats
that
would
allow
use
of
other
control
technologies
if
the
equivalent
emission
reduction
is
achieved.

The
impact
estimates
are
based
on
average,
representative,
or
typical
emissions
and
control
requirements
for
each
kind
of
source.
Thus,
the
estimates
do
not
reflect
the
impact
that
would
be
observed
at
any
particular
refinery.
However,
they
do
provide
a
reasonable
estimate
of
nationwide
emission
reductions
and
represent
the
range
of
control
costs
that
refineries
might
incur
under
different
regulatory
alternatives.

The
specific
procedures
used
to
estimate
baseline
emissions
and
the
costs
and
emission
reductions
for
the
different
control
alternatives
for
each
kind
of
emission
point
are
described
separately
for
new
and
existing
sources.

5.1.2
Calculations
for
Existing
Sources
For
existing
petroleum
refinery
sources,
baseline
emissions
and
control
impacts
were
calculated
for
the
four
sources
for
individual
refineries
and
aggregated
to
determine
nationwide
impacts.
Some
sources
were
not
as
well
characterized
as
others.

In
these
cases,
the
available
information
was
extrapolated
to
derive
nationwide
estimates.

5.1.2.1
Storage
Vessels.
Emissions
and
emission
reductions
from
storage
vessels
are
a
function
of
the
volatility
of
the
material
stored
and
the
type
of
storage
vessel.
Responses
to
questionnaires
sent
to
refineries
provided
information
on
the
volatility
and
HAP
content
of
materials
stored
and
the
types
of
vessels
used
to
store
materials.
Based
on
information
in
the
questionnaire
responses,
factors
for
storage
vessel
population
and
VOC
emissions
were
developed
and
used
to
estimate
baseline
emissions
of
HAPs
and
VOC,
emission
reductions
at
the
floor
level
of
control
and
above,
and
costs
for
controlling
emissions
to
the
floor
level
of
control
and
to
levels
more
stringent
than
the
floor.
Thirteen
"
major"
petroleum
liquids
were
included
in
this
analysis:
crude
oil,
gasoline,
naphtha,
asphalt,
alkylate,

reformate,
jet
kerosene/
kerosene,
heavy
gas
oil,
aviation
gasoline,
diesel/
distillate,
jet
fuel
(#
4),
residual
fuel
oil,

and
slop
oil.
In
a
previous
analysis
using
all
available
80
information,
these
13
petroleum
liquids
accounted
for
more
than
80
percent
of
the
estimated
nationwide
baseline
VOC
emissions.

The
storage
vessel
population
factors
were
used
to
estimate
the
total
number
of
vessels
at
each
refinery.
The
storage
vessels
reported
in
the
questionnaire
responses
were
divided
into
groups
based
on
storage
vessel
type
(
e.
g.,
fixed
roof),
refinery
crude
capacity
(
greater
than
or
less
than
150,000
barrels
per
calendar
day
(
bbls/
cd)),
and
petroleum
liquid
stored
(
e.
g.,

gasoline,
naphtha,
etc.).
The
average
number
of
vessels
in
each
group
per
barrel
of
crude
capacity
at
a
refinery
was
the
tank
population
factor.
For
example,
the
questionnaire
responses
indicated
that
the
number
of
internal
floating
roof
vessels
storing
gasoline
at
refineries
with
crude
capacities
greater
than
150,000
bbls/
cd
was
1.2
x
10
­
5
storage
vessels
per
barrel
of
crude
capacity
per
day.
That
is,
a
refinery
of
267,000
barrels
per
day
would
have
two
internal
floating
roof
tanks
storing
gasoline.

VOC
emission
factors
were
calculated
for
each
storage
vessel
grouping.
To
calculate
the
VOC
factor,
VOC
emissions
from
the
storage
vessels
reported
in
the
questionnaire
responses
were
estimated
using
equations
in
chapter
12
of
AP­
42.
Where
data
were
missing
or
insufficient,
default
values,
developed
from
information
in
the
questionnaire
responses,
were
used.
Average
VOC
emission
factors
at
the
baseline
level
of
control
were
then
calculated
for
each
vessel
grouping.
For
example,
for
internal
floating
roof
vessels
storing
gasoline
at
refineries
with
crude
capacities
greater
than
150,000
bbls/
cd,
an
average
VOC
emission
factor
of
15,000
lbs
VOC
emitted/
vessel
was
calculated.

The
number
of
vessels
and
the
baseline
VOC
emissions
nationwide
were
estimated
in
the
following
way.
The
crude
capacity
of
each
refinery
in
the
nation,
as
listed
in
OGJ,
was
multiplied
by
the
population
factor
for
each
applicable
type
of
vessel
to
estimate
the
numbers
and
types
of
vessels
at
each
refinery.
This
yielded
the
nationwide
storage
vessel
population.

The
baseline
VOC
emission
factor
(
lb
VOC
emitted/
vessel)

corresponding
to
each
vessel
type
was
multiplied
by
the
number
of
vessels
of
that
type
to
calculate
the
baseline
VOC
emissions
at
81
each
refinery.
For
example,
for
internal
floating
roof
vessels
storing
gasoline
at
refineries
with
crude
capacities
greater
than
150,000
bbls/
cd
the
refinery
crude
capacity,
times
the
tank
population
factor
of
1.2
x
10
­
5
vessels
per
barrel,
times
the
VOC
emission
factor
of
15,000
lb
VOC
emitted/
vessel
yielded
the
estimated
VOC
emissions.
Certain
petroleum
liquids
(
e.
g.,

asphalt,
alkylate,
and
reformate)
are
directly
associated
with
specific
process
units.
If
OGJ
did
not
list
capacities
for
these
specific
process
units,
then
the
vessel
population
factor
corresponding
to
that
process
unit
was
not
applied
to
that
refinery.
(
For
more
information,
refer
to
"
Summary
of
Nationwide
Volatile
Organic
Compound
and
Hazardous
Air
Pollutant
Emission
Estimates
from
Petroleum
Refineries,"
in
the
docket).

Emissions
of
HAPs
were
estimated
by
multiplying
the
VOC
emissions
calculated
for
each
type
of
material
stored
by
the
average
HAP
weight
fraction
in
the
vapor
phase
of
the
material.

Average
vapor
phase
HAP
weight
fractions
were
calculated
from
the
HAP
liquid
concentrations
(
obtained
from
industry
questionnaire
responses)
using
Raoult's
Law
and
the
vapor
pressure
of
the
individual
HAPs.

Emission
reductions
and
costs
for
control
options
were
estimated
using
the
extrapolated
nationwide
storage
vessel
population.
For
all
control
options,
factors
for
average
emission
reduction
and
costs
were
developed
by
calculating
specific
emission
reductions
and
costs
for
the
3,400
storage
vessels
reported
in
the
questionnaire
responses.
Average
emission
reduction
and
cost
factors
were
then
calculated
for
each
storage
vessel
group.

An
analysis
of
refinery
storage
vessels
indicated
that
the
MACT
floor
level
of
control
for
existing
sources
is
an
internal
floating
roof
with
seals
that
comply
with
the
NSPS
for
and
with
the
hazardous
organic
NESHAP
(
HON)
storage.
Costs
were
estimated
for
equipping
existing
fixed
roof
storage
vessels
with
an
internal
floating
roof
and
seals
that
comply
with
specifications
in
the
storage
NSPS
(
40
CFR
60
subpart
Kb)
and
HON
(
40
CFR
63
subpart
G).
For
existing
external
and
internal
floating
roof
vessels,
costs
were
estimated
for
installing
seals
that
comply
with
the
proposed
HON
seal
requirements.
The
MACT
floor
level
of
82
control
for
existing
floating
roof
storage
vessels
does
not
include
complying
with
the
fitting
requirements
in
the
proposed
HON.

More
stringent
controls
were
not
identified
for
existing
fixed
roof
storage
vessels.
For
existing
external
and
internal
floating
roof
vessels,
the
more
stringent
control
alternative
is
to
comply
with
the
fitting
requirements
in
the
proposed
HON
in
addition
to
the
seal
requirements.

The
emission
reduction
assigned
to
each
of
the
3,400
storage
vessels
was
calculated
as
a
function
of
the
emission
reductions
presented
in
the
EPA
publication
"
NSPS
VOC
Emissions
from
VOL
Storage
Tanks­­
Background
Information
for
Proposed
Standards".

This
document
provided
the
emission
reduction
(
in
percent)
of
various
seal
and
fitting
configurations
compared
with
fixed
roof
vessels.
For
example,
an
internal
floating
roof
vessel
with
a
liquid
mounted
primary
seal
and
controlled
fittings
has
an
average
emission
reduction
of
96.2
percent
over
a
similar
sized
fixed
roof
vessel.
Adding
a
rim­
mounted
secondary
seal
increases
this
emission
reduction
to
96.6
percent.
Therefore,
the
incremental
emission
reduction
gained
by
adding
the
rim
mounted
secondary
seal
is
0.4
percent.
The
emission
reduction
applied
to
each
storage
vessel
was
calculated
as
the
difference
between
the
level
of
control
required
by
the
control
option
and
the
baseline
level
of
control.

The
cost
equations
for
converting
existing
fixed
roof
vessels
to
internal
floating
roof
vessels
were
taken
from
the
"
Control
of
Volatile
Organic
Compound
Emissions
from
Volatile
Organic
Liquid
Storage
in
Floating
and
Fixed
Roof
Tanks"
(
Draft,
July
1992),
and
"
Internal
Instruction
Manual
for
ESD
Regulation­
Storage
Tanks"

(
January
1993).
The
cost
equations
for
adding
seals
and
controlled
fittings
to
existing
external
and
internal
floating
roof
vessels
were
also
taken
from
these
two
documents.

5.1.2.2
Wastewater
Collection
and
Treatment
Systems.

Emissions
and
emission
reductions
from
wastewater
collection
and
treatment
systems
are
both
a
function
of
wastewater
stream
flow,

the
HAP
compound
concentration
in
the
wastewater,
and
the
volatility
of
the
HAP
compounds
in
the
wastewater.
Emission
83
reductions
are
also
a
function
of
the
design
and
operating
parameters
of
the
control
device.

EPA
gathered
data
for
the
wastewater
stream
flow
rate
and
the
concentration
of
HAPs
in
petroleum
refinery
wastewater
to
develop
models
of
wastewater
from
process
units
found
at
refineries.

Each
model
process
unit
was
assigned
representative
values
for
the
concentration
and
volatility
of
the
HAPs
in
its
wastewater
stream.
A
ratio
of
wastewater
stream
flow
to
refinery
crude
capacity
was
also
developed
for
each
model
process
unit
and
applied
to
the
capacities
reported
in
OGJ
for
each
process
unit
at
each
refinery.
(
For
more
information,
refer
to
"
Data
Summary
for
Petroleum
Refinery
Wastewater,"
in
the
docket).
Mass
loadings
of
volatile
HAP
in
wastewater
were
determined
by
multiplying
volatile
HAP
concentrations
by
capacity­
based
wastewater
stream
flow
rates
for
each
process
unit
at
each
refinery
in
the
nation.
The
results
of
prior
EPA
analyses
developed
for
the
HON
were
judged
to
be
appropriate
to
use
to
estimate
the
cumulative
mass
fraction
of
HAPs
emitted
from
wastewater
collection
and
treatment
systems.

Uncontrolled
emissions
were
determined
by
multiplying
the
mass
fraction
of
HAPs
emitted
by
the
mass
loading
of
volatile
HAPs.

However,
many
petroleum
refineries
control
their
wastewater
collection
and
treatment
systems
in
accordance
with
the
BWON.

(
For
more
information,
refer
to
"
The
Effectiveness
of
the
BWON
in
Controlling
Volatile
HAP
Mass
Loading
in
Petroleum
Refinery
Wastewater,"
in
the
docket).
These
controls
were
credited
in
the
national
baseline
emissions
calculations
by
applying
the
applicability
criteria
of
the
BWON
(
i.
e.,
wastewater
streams
with
flows
greater
than
0.02
l/
min
and
benzene
concentration
of
10
ppmw
or
greater
at
a
facility
with
at
least
10
Mg/
yr
total
annual
benzene
loading
in
wastes
and
wastewater)
to
each
refinery
and
wastewater
stream
and
by
assuming
that
the
control
requirements
of
the
BWON
(
i.
e.,
99
percent
reduction
of
benzene)

were
met
for
those
streams
requiring
control.

An
analysis
of
existing
refinery
wastewater
collection
and
treatment
systems
indicated
that
the
MACT
floor
for
wastewater
is
84
the
BWON.
(
For
more
information,
refer
to
["
Maximum
Achievable
Control
Technology
Floor
for
Process
Wastewater
Streams
at
Petroleum
Refineries,"]
in
the
docket).
Existing
refineries
are
already
required
to
comply
with
the
BWON,
so
no
emission
reductions
or
costs
would
be
associated
with
the
floor
option
for
refinery
wastewater
sources.
In
considering
a
control
option
more
stringent
than
the
BWON,
the
EPA
assessed
the
effects
of
lowering
the
applicability
threshold
of
the
BWON,
by
eliminating
the
cutoff
of
10
Mg/
yr
TAB
loading
in
facility
wastes
and
wastewater.
The
additional
wastewater
streams
requiring
control
(
those
streams
with
at
least
10
ppmw
benzene
at
refineries
with
a
TAB
under
the
10
Mg/
yr
loading
criterion)
were
assumed
to
be
steam
stripped
to
achieve
reductions
equivalent
to
the
requirements
of
the
BWON
(
e.
g.,
99
percent
reduction
of
benzene).

The
overheads
from
the
steam
stripper
were
assumed
to
be
sent
to
a
combustion
device.
(
For
more
information,
refer
to
["
Control
Option
Above
the
Floor
for
Petroleum
Refinery
Process
Wastewater,"]
in
the
docket).
The
results
of
prior
EPA
analyses
were
used
to
estimate
the
mass
fraction
of
HAPs
removed
from
a
wastewater
stream
by
a
steam
stripper
as
well
as
the
costs
associated
with
the
stripper
system.
(
For
more
information,

refer
to
"
Steam
Stripper
Removals
and
Costing
for
Petroleum
Refinery
Wastewater,"
in
the
docket).
The
results
of
those
analyses
indicate
that
the
selected
steam
stripper
design
and
operating
parameters
achieve
a
95
to
99
percent
removal,

depending
on
the
volatility
of
the
HAPs
in
the
stream.

5.1.2.3
Equipment
Leaks.
Emissions
and
emission
reductions
from
leaking
equipment
are
a
function
of
the
component
counts
and
the
control
program
used
to
reduce
emissions.
The
questionnaires
were
designed
to
obtain
equipment
leak
information
for
18
different
refinery
process
units
because
the
controls
required
may
vary
from
process
unit
to
process
unit.
The
questionnaire
responses
included
information
on
component
counts,
the
HAP
content
of
refinery
process
streams,
and
the
monitoring
frequencies
and
leak
definitions
used
for
leak
detection
and
repair
programs
for
each
refinery
process
unit.
The
monitoring
frequencies
and
leak
definitions
reported
for
each
process
unit
85
were
matched
to
the
requirements
of
existing
LDAR
programs
to
determine
which
control
program
was
being
used
to
reduce
emissions.

Data
on
equipment
leaks
were
reported
by
approximately
70
percent
of
the
refineries
in
the
nation.
For
those
refineries
not
reporting
information,
the
characteristics
of
model
process
units
(
for
each
of
the
18
process
units
of
interest)
were
assigned
to
the
refinery
based
on
information
in
OGJ.
The
model
process
units
were
developed
as
the
median
component
count
of
the
process
units
from
refineries
reporting
information
in
the
surveys.
If
OGJ
data
indicated
that
a
refinery
contained
a
specific
process
unit,
then
the
median
counts
for
the
model
representing
that
process
unit
was
assigned
to
the
refinery.
If
the
refinery
was
determined
to
be
in
an
ozone
nonattainment
area,

the
EPA
assumed
that
the
refinery
would
be
controlled
to
the
level
of
control
in
the
petroleum
refinery
CTG.

Uncontrolled
HAP
emissions
from
each
of
the
18
different
refinery
process
units
were
estimated
by
multiplying
the
uncontrolled
VOC
emissions
from
each
unit
by
the
average
HAP­
to­
VOC
ratio
of
the
streams
associated
with
each
unit.

Uncontrolled
VOC
emissions
from
leaking
equipment
were
estimated
on
a
process
unit
basis
by
multiplying
the
component
counts
for
the
process
unit
by
VOC
emission
factors
for
each
equipment
component.
The
VOC
emission
factors
relate
VOC
emissions
to
the
type
of
component
leaking
(
e.
g.,
pumps,
valves,
etc.)
in
units
of
lb/
hr/
component
type.
The
emission
factors
used
for
the
impacts
analysis
were
taken
from
a
previous
EPA
study
on
leaking
refinery
equipment
and
presented
in
chapter
9
of
AP­
42.
These
emission
factors
are
currently
being
reviewed
by
EPA
based
on
new
industry
data.
The
emission
estimates
may
be
revised
at
promulgation
if
new
factors
are
developed
by
EPA
based
on
the
new
industry
data.

Baseline
emissions
of
HAPs
and
VOC
were
estimated
by
multiplying
the
uncontrolled
emissions
by
one
minus
the
control
efficiencies
associated
with
each
LDAR
program
reported
by
or
assigned
to
each
refinery.
The
"
Equipment
Leaks
Enabling
Document"
(
in
the
docket)
provides
information
on
the
control
efficiencies
that
may
be
achieved
by
monitoring
components
under
86
various
LDAR
programs.
(
For
more
information,
refer
to
"
Summary
of
Nationwide
Volatile
Organic
Compound
and
Hazardous
Air
Pollutant
Emission
Estimates
from
Petroleum
Refineries,"
in
the
docket).

An
analysis
of
existing
controls
on
refinery
equipment
leaks
indicated
that
the
MACT
floor
level
of
control
for
refinery
equipment
leaks
was
the
control
required
by
the
Petroleum
Refinery
NSPS.
For
more
information
refer
to
["
Maximum
Achievable
Control
Technology
Floor
for
Equipment
Leaks
at
Petroleum
Refineries,"
in
the
docket].
Two
more
stringent
control
options
were
also
analyzed:
(
1)
compliance
with
the
negotiated
equipment
leaks
regulation
included
in
the
HON,

without
the
monitoring
requirements
for
connectors,
and
(
2)
compliance
with
the
negotiated
equipment
leaks
regulation
included
in
the
HON.
Each
of
these
options
requires
specific
leak
monitoring
frequencies
for
components
and
control
devices.

Emission
reductions
for
controlling
leaking
equipment
to
the
level
of
control
required
by
the
NSPS
and
the
two
more
stringent
options
were
calculated
from
the
difference
between
baseline
emissions
and
the
emissions
calculated
using
the
percent
reductions
associated
with
the
petroleum
refinery
NSPS
and
the
HON
equipment
leaks
negotiated
rule.
Similarly,
the
cost
impact
of
controlling
leaking
equipment
to
the
level
required
by
the
NSPS
and
the
two
more
stringent
control
options
was
calculated
from
the
cost
of
control
devices
and
labor
associated
with
the
petroleum
refinery
NSPS
and
the
negotiated
rule.
The
cost
methodology
was
based
on
procedures
provided
in
the
"
Equipment
Leaks
Enabling
Document."
(
For
more
information,
refer
to
["
Costs
for
the
MACT
Floor
Level
of
Control
and
Control
Options
Above
the
Floor
for
Controlling
Emissions
from
Leaking
Refinery
Equipment,"]
in
the
docket).

5.1.2.4
Miscellaneous
Process
Vents.
The
miscellaneous
process
vent
group
includes
most
miscellaneous
process
vents
that
emit
organic
HAPs
at
refineries
other
than
FCCU
catalyst
regeneration
vents,
catalyst
reformer
catalyst
regeneration
vents,
and
sulfur
plant
vents.
The
baseline
HAP
emissions
from
miscellaneous
process
vents
were
estimated
by
multiplying
HAP
87
emission
factors
by
the
charge
capacities
of
refinery
processes.

Specific
HAP
emission
factors
were
developed
by
dividing
the
HAP
emissions
reported
in
questionnaire
responses
by
the
charge
capacities
of
those
refineries
reporting
the
specific
HAP.
(
For
further
information,
refer
to
"
Summary
of
Nationwide
Volatile
Organic
Compound
and
Hazardous
Air
Pollutant
Emission
Estimates
from
Petroleum
Refineries,"
in
the
docket).

The
MACT
floor
level
of
control
for
these
vents
was
combustion.
EPA
has
determined
that
combustion
of
emissions
can
achieve
98
percent
organic
HAP
reduction,
so
emission
reductions
were
calculated
by
applying
this
percent
reduction
to
emissions
from
miscellaneous
process
vents
that
are
uncontrolled
at
baseline.
The
cost
for
controlling
emissions
from
miscellaneous
vents
includes
the
cost
for
piping
emissions
to
existing
control
devices
and
an
additional
compressor
for
the
refinery.
EPA
assumed
that
refineries
would
already
have
an
existing
fuel
gas
or
flare
system
that
could
be
used
to
reduce
emissions
from
miscellaneous
process
vents.
Further
information
on
costing
procedures
and
specific
assumptions
is
contained
in
"
Costing
Methodology
for
Controlling
Emissions
for
Miscellaneous
Process
Vents,"
in
the
docket.

5.1.3
Calculations
for
New
Sources
This
section
explains
the
methodology
used
for
estimating
emissions
and
control
impacts
in
the
first
5
years
after
the
promulgation
of
this
rule.
These
costs
represent
control
of
new
process
units
and
equipment
built
within
the
first
5
years
after
promulgation.
It
should
be
noted
for
regulatory
purposes,
that
some
of
these
units
and
equipment
will
be
considered
"
new
sources"
and
others
will
be
considered
part
of
an
"
existing
source".
It
is
not
possible
to
determine
how
many
new
units
will
fall
into
each
of
these
categories;
however,
controls
will
be
required
for
the
emission
points
in
either
case.

Costs
for
controlling
new
process
units
were
estimated
from
the
costs
calculated
for
existing
sources
and
the
number
of
new
process
units
that
are
expected
to
be
constructed
in
the
5­
year
period
after
the
standard
is
enacted.
The
costs
for
applying
control
technologies
to
existing
sources
were
calculated
as
88
previously
described.
The
results
are
documented
in
the
four
memoranda
presenting
cost
impacts
(
in
the
docket).
The
cost
information
was
scaled
up
to
account
for
new
emission
points
that
may
need
to
be
controlled
in
the
first
5
years
after
the
petroleum
refinery
NESHAP
has
been
promulgated.
Reductions
of
emissions
of
HAPs
and
VOC
from
controlling
existing
emission
points
were
also
presented
in
the
costing
memorandum.
The
emission
reduction
information
was
scaled
up
to
account
for
controls
on
new
emission
points
using
the
same
methodology
that
was
used
to
scale
up
cost
data.
(
For
further
information,
refer
to
"
Estimation
of
Annual
Costs
for
New
Petroleum
Refinery
Emission
Points
in
the
Fifth
Year
After
Promulgation,"
in
the
docket).

OGJ
provided
estimates
of
annual
refinery
construction
projects.
This
information
was
used
to
determine
an
average
number
of
process
units
constructed
in
a
year.

5.1.3.1
Storage
Vessels.
The
MACT
floor
for
storage
vessels
at
new
sources
is
application
of
seals
and
fittings
equivalent
to
those
required
by
40
CFR
60
subpart
Kb
(
the
NSPS
for
VOL
storage)

to
storage
vessels
larger
than
151
m3
(
947
bbl)
with
vapor
pressures
above
3.5
kPa
(
0.50
psia).
(
These
seals
and
fittings
are
the
same
as
those
required
by
the
HON.)
The
petroleum
refinery
NESHAP
would
result
in
no
costs
or
emission
reductions
for
those
storage
vessels
required
to
comply
with
subpart
Kb
(
all
new
vessels
with
a
capacity
greater
than
or
equal
to
40
m
3
or
250
bbl).
This
methodology
may
overestimate
the
impact
of
the
regulation
in
the
5
years
after
promulgation
because,
as
previously
stated,
many
vessels
constructed
in
that
period
may
be
considered
part
of
existing
sources
for
regulatory
purposes.

Because
the
requirements
for
existing
sources
are
equivalent
to
the
NSPS,
there
will
be
no
costs
or
emission
reductions
for
existing
storage
vessels.
Therefore,
the
fifth
year
impacts
on
vessels
at
new
sources
would
be
lower
than
the
impact
estimated
here
because
the
number
of
vessels
at
new
sources
is
probably
overestimated.

5.1.3.2
Wastewater
Collection
and
Treatment
Systems.
A
MACT
floor
analysis
performed
on
wastewater
collection
and
treatment
89
systems
indicated
that
the
MACT
floor
level
of
control
for
wastewater
streams
at
new
sources
is
compliance
with
the
BWON.

Therefore,
no
costs
are
anticipated
for
sources
built
in
the
5
years
after
promulgation
to
reach
the
MACT
floor
level
of
control.
The
control
option
more
stringent
than
the
floor
that
was
considered
was
the
same
as
the
option
considered
for
existing
sources:
assessing
the
effects
of
lowering
the
applicability
threshold
of
the
BWON
by
eliminating
the
cutoff
of
10
Mg/
yr
TAB
loading
in
facility
wastes
and
wastewater.

The
average
annual
number
of
newly
constructed
process
units
that
will
generate
wastewater
is
expected
to
be
approximately
34.

The
distribution
of
these
new
units
across
refinery
processes
was
based
on
OGJ
data.
(
For
more
information,
refer
to
the
docket).

Using
the
same
approach
for
applying
controls
and
estimating
costs
for
new
sources
as
for
existing
sources,
costs
for
the
newly
constructed
units
were
estimated.
The
total
estimated
capital
investment
for
controls
by
the
fifth
year
(
considering
34
new
units
per
year
over
the
5­
year
period)
would
be
approximately
$
42
million.
The
total
annual
cost
to
be
expended
in
the
fifth
year
(
considering
all
170
new
units)
would
be
approximately
$
18
million
per
year.

5.1.3.3
Equipment
Leaks.
OGJ
provides
annual
construction
projects
in
petroleum
refineries
and
expected
dates
of
completion.
This
information,
for
a
5­
year
period
from
1988
to
1992,
was
used
to
develop
an
average
count
of
new
construction
projects
5
years
after
promulgation
of
the
refinery
NESHAP.
From
this
information,
it
was
determined
that
an
average
of
34
process
units
would
be
built
annually.
Each
of
these
process
units
is
expected
to
require
control
under
the
NSPS
for
refineries.

Therefore,
the
only
cost
associated
with
controlling
these
units
is
the
extra
cost
required
to
go
from
the
NSPS
control
requirements
(
the
MACT
floor
for
equipment
leaks
at
new
sources)

to
the
two
options
more
stringent
than
floor.
The
two
options
are
the
same
as
for
existing
sources:
(
1)
the
negotiated
regulation
for
equipment
leaks
in
the
HON
(
40
CFR
63
subpart
H)

without
the
monitoring
requirements
for
connectors
and
(
2)
the
HON
negotiated
regulation.
90
The
average
capital
investment
cost
and
annual
cost
of
upgrading
from
the
NSPS
to
the
HON
negotiated
regulation
without
connector
monitoring
were
determined
to
be
$
20,000
and
$
7,000/
yr
per
process
unit,
respectively.
The
average
capital
investment
and
annual
cost
of
upgrading
from
the
NSPS
to
the
HON
negotiated
regulation
were
determined
to
be
$
17,000
and
$
6,200/
yr
per
process
unit,
respectively.
For
each
option,
the
capital
investment
cost
and
average
annual
cost
for
controlling
the
34
process
units
constructed
each
year
was
calculated
by
multiplying
the
average
cost
per
process
unit
by
the
number
of
new
process
units.

5.1.3.4
Miscellaneous
Process
Vents.
The
MACT
floor
level
of
control
for
miscellaneous
process
vents
at
new
sources
was
determined
to
be
combustion.
The
annual
cost
for
controlling
emissions
from
miscellaneous
vents
consisted
the
cost
for
piping
to
an
existing
combustion
system
(
to
a
flare
or
to
the
fuel
gas
system)
and
for
an
additional
compressor
for
each
refinery.
The
average
capital
cost
for
piping
for
each
vent
and
a
compressor
for
each
refinery
was
determined
to
be
$
9,910
and
$
66,100,

respectively,
and
the
average
annual
cost
of
piping
for
each
vent
and
compressor
for
each
refinery
was
determined
to
be
$
2,170
and
$
37,800,
respectively.

As
previously
stated,
the
average
annual
number
of
newly
constructed
process
units
is
expected
to
be
34.
The
number
of
miscellaneous
vents
requiring
control
was
calculated
from
the
average
number
of
uncontrolled
vents
per
process
unit,
as
presented
in
the
baseline
emissions
estimation
memorandum
(
refer
to
docket).
Based
on
this
information,
one
vent
for
each
of
the
34
process
units
is
estimated
to
require
control
(
that
is,
a
total
of
34
new
vents
will
require
control
each
year).
This
number
of
vents
per
year
was
multiplied
by
the
average
cost
per
vent
to
estimate
national
costs
for
miscellaneous
process
vents
for
process
units
constructed
in
the
5
years
after
promulgation
of
this
rule.

5.2
TOTAL
COMPLIANCE
COST
ESTIMATES,
REDUCTIONS,
AND
COST
EFFECTIVENESS
91
The
annualized
compliance
costs
by
emission
point
are
shown
in
Table
5­
1
for
the
chosen
alternative.
The
total
national
cost
of
Alternative
1
in
the
fifth
year
is
$
79
million.
Table
5­
2
presents
the
costs,
HAP
emission
reductions,
and
cost
effectiveness
for
the
control
options
by
emission
point.
The
average
cost
effectiveness
of
the
regulation
($/
Mg
of
pollutant
removed)
is
determined
by
dividing
the
annual
cost
by
the
annual
emission
reduction.
Table
5­
3
presents
a
summary
of
the
HAP
emission
reductions,
total
cost,
and
cost
effectiveness
values
for
the
chosen
regulatory
alternatives.
The
emission
reductions
associated
with
the
alternatives
in
Table
5­
3
were
calculated
by
summing
the
HAP
emission
reductions
listed
in
Table
5­
2
for
the
control
option
chosen
at
each
emission
point.
The
annual
costs
are
as
reported
in
Table
5­
1,
and
the
cost
effectiveness
values
were
calculated
as
described
above.
The
incremental
cost
effectiveness
represents
the
increase
in
cost
from
Alternative
1
to
Alternative
2
divided
by
the
increased
HAP
emission
reduction.

Table
5­
4
reports
similar
information
for
VOC
emissions.
TABLE
5­
1.
SUMMARY
OF
TOTAL
ANNUAL
COSTS
IN
THE
FIFTH
YEAR
FOR
THE
PETROLEUM
REFINING
NESHAP
Annual
Fifth
Year
Costs
(
1000$/
yr)
3
(
1992
Dollars)

Emission
Point
Option
Existing
Sources
New
Construction
Total
Alternative
1
Equipment
Leaks
Miscellaneous
Process
Vents
Wastewater
Systems
Storage
Vessels
Floor
Option
11
Floor2
Floor1
Floor1
$
69,000
$
58,000
$
12,000
$
0
$
8,000
$
0
$(
210)

$
370
$
0
$
98
$
69,000
$
57,790
$
12,370
$
0
$
8,098
$
65,790
$
11,370
$
0
$
3,798
Other
Recordkeeping
and
Reporting
TOTAL
COST
$
1,000
$
79,190
NOTES:
1Alternative
1.

2EPA
did
not
choose
an
option
above
the
MACT
floor
for
miscellaneous
process
vents.

3Costs
are
in
1992
dollars.
TABLE
5­
2.
CONTROL
OPTIONS
AND
IMPACTS
BY
EMISSION
POINT
HAP
Cost
Effectiveness
($/
Mg
HAP)

Emission
Point
Baseline
HAP
Emissions
(
Mg/
yr)
Control
Option
Emission
Reductio
n
(
Mg/
yr)
Percent
Emission
Reduction
Annual
Cost
($
1,000/

yr)
b
Average
Incrementa
l
Miscellaneous
Process
Vents
Existing
Sources
8,900
Floor*
7,600
85
$
11,000
$
1,500
N/
A
New
Sourcesa
900
Floor*
770
85
$
370
$
480
N/
A
Storage
Vessels
Existing
Sources
9,000
Floor*
670
7
$
3,700
$
5,500
N/
A
Option
1
1,300
14
$
6,200
$
4,800
$
4,000
Option
2
1,800
20
$
8,400
$
4,700
$
4,400
Option
3
2,600
29
$
32,000
$
12,000
$
30,000
New
Sourcesa
290
Floor*
4
1.4
$
98
$
24,000
N/
A
Option
1
14
4.8
$
550
$
39,000
$
45,000
Wastewater
Systems
Existing
Sources
9,200
Floor*
0
N/
A
0
N/
A
N/
A
Option
1
7,700
93
$
120,000
$
15,000
$
15,000
New
Sourcesa
960
Floor*
0
N/
A
0
N/
A
N/
A
Option
1
930
97
$
18,000
$
20,000
$
20,000
Equipment
Leaks
Existing
Sources
50,000
Floor
35,000
69
$
69,000
$
2,000
N/
A
Option
1*
44,000
87
$
58,000
$
1,500
$(
330)

Option
2
46,000
91
$
78,000
$
1,700
$
6,000
New
Sources
1,300
Floor
0
0
0
0
0
Option
1*
640
49
$(
210)
$(
330)
$(
330)

Option
2
760
59
$
840
$
1,100
$
8,300
94
NOTES:
aImpacts
were
estimated
for
new
process
units
constructed
in
the
5
years
after
promulgation.
For
regulatory
purposes,
some
of
these
units
may
be
considered
new
sources
while
others
may
be
considered
part
of
an
existing
source.

bThe
costs
for
monitoring,
recordkeeping,
and
reporting
(
MRR)
requirements
are
not
available
on
an
emission
point
basis.
The
costs
in
this
table
reflect
costs
for
operation
and
maintenance
of
control
equipment
only.

N/
A
=
Not
applicable.

Brackets
indicate
negative
values.

*
=
Control
option
chosen
for
preferred
alternative.
95
TABLE
5­
3.
COST,
HAP
EMISSION
REDUCTION,
AND
COST
EFFECTIVENESS
BY
ALTERNATIVE
HAP
Emissions
(
Mg/
Yr)
Cost
Effectiveness
($/
Mg)

Regulatory
Alternative
Reduction
Annual
Cost
(
Million
$,
1992)
1
Averag
e
Increment
al
Alternative
1
48,000
$
79.0
$
1,645
N/
A
NOTES:
N/
A
=
Not
applicable.
1Cost
estimates
do
include
costs
associated
with
monitoring,
recordkeeping,
and
reporting
requirements.

TABLE
5­
4.
COST,
VOC
EMISSION
REDUCTION,
AND
COST
EFFECTIVENESS
BY
ALTERNATIVE
Cost
Effectiveness
VOC
Emission
Annual
Cost
($/
Mg)
Regulatory
Alternative
Reduction
(
Mg/
Yr)
1
(
Million
$,
1992)
2
Averag
e
Increment
al
Alternative
1
252,000
$
79.0
$
313
N/
A
NOTES:
N/
A
=
Not
applicable.
1Emission
reduction
estimates
do
not
incorporate
reductions
occurring
at
new
sources.
96
5.3
MONITORING,
RECORDKEEPING,
AND
REPORTING
COSTS
In
addition
to
provisions
for
the
installation
of
control
equipment,
the
promulgated
regulation
includes
provisions
for
MRR.
EPA
estimates
that
the
total
annual
cost
for
refineries
to
comply
with
the
MRR
requirements
is
$
21
million.
After
incorporating
MRR
costs,
the
total
cost
of
compliance
of
Alternative
1
is
$
79
million.
For
Alternative
1,
the
incorporation
of
MRR
costs
into
total
annual
cost
results
in
an
average
cost
effectiveness
of
$
313
for
each
megagram
of
VOC
reduced
and
$
1,645
for
each
megagram
of
HAP
reduced.

In
order
to
calculate
the
costs
of
MRR
associated
with
the
petroleum
refinery
NESHAP,
estimates
of
hours
per
item
(
i.
e.,
a
required
MRR
action),
frequency
of
required
action
per
year,
and
number
of
respondents
(
i.
e.,
total
number
of
individuals
required
to
submit
compliance
reports)
were
estimated
based
on
the
requirements
in
the
proposed
rule
for
all
of
the
emission
points.

To
compute
the
costs
associated
with
the
burden
estimates,
a
wage
rate
of
$
32
per
hour
(
in
1992
dollars)
was
assumed.
This
assumption
was
based
on
an
estimate
that
85
percent
of
the
labor
will
be
accomplished
by
technical
personnel
(
typically
by
an
engineer
with
a
wage
rate
of
$
33
per
hour),
10
percent
will
be
completed
by
a
manager
(
at
$
49
per
hour),
and
5
percent
by
clerical
personnel
(
at
$
15
per
hour).
All
of
the
wage
rates
include
an
additional
110
percent
for
overhead.
Costs
were
annualized
assuming
an
expected
remaining
life
for
affected
facilities
of
15
years
from
the
date
of
promulgation
of
the
subject
NESHAP,
and
using
an
interest
rate
of
7
percent.

Compliance
requirements
vary
in
terms
of
frequency.
This
variance
is
taken
into
account
in
the
annualization
of
costs.

Performance
tests
to
demonstrate
compliance
with
the
control
device
requirements
are
required
once.
Compliance
requirements
also
include
monitoring
of
operating
parameters
of
control
devices
and
records
of
work
practice
and
other
inspections.

These
activities
must
be
reported
semiannually.
The
compliance
requirements
that
must
be
met
only
once
are
annualized
over
the
time
from
the
year
in
which
they
are
to
take
place
to
the
expected
end
of
facility
life.
97
The
MRR
requirements
are
outlined
separately
in
the
regulation
for
each
emission
point.
The
compliance
determination
provisions
for
storage
vessels
include
inspections
of
vessels
and
roof
seals.
If
a
closed
vent
system
and
control
device
is
used
for
venting
emissions
from
storage
vessels,
the
owner
must
establish
appropriate
monitoring
procedures.
For
wastewater
stream
and
treatment
operations,
the
MRR
requirements
are
outlined
in
the
rule
for
the
BWON.

For
miscellaneous
process
vents,
the
promulgated
standard
specifies
the
performance
tests,
monitoring
requirements,
and
test
methods
necessary
to
determine
whether
a
miscellaneous
process
vent
stream
is
required
to
apply
control
devices
and
to
demonstrate
that
the
allowed
emission
levels
are
achieved
when
controls
are
applied.
The
format
of
these
requirements,
as
with
the
format
of
the
miscellaneous
process
vent
provisions,
depends
on
the
control
device
selected.
The
MRR
requirements
for
miscellaneous
process
vents
are
summarized
by
control
device
in
Table
5­
5.

For
equipment
leaks,
because
the
provisions
of
the
proposed
rule
are
work
practice
and
equipment
standards,
monitoring,

repairing
leaks,
and
maintaining
the
required
records
constitutes
compliance
with
the
rule.
The
HON
equipment
leak
provisions
are
appropriate
to
determine
continuous
compliance
with
the
petroleum
refinery
equipment
leak
standards.
In
summary,
these
provisions
require
periodic
monitoring
with
a
portable
hydrocarbon
detector
to
determine
if
equipment
is
leaking.
TABLE
5­
5.
MISCELLANEOUS
PROCESS
VENTS
C
MONITORING,
RECORDKEEPING,
AND
REPORTING
REQUIREMENTS
FOR
COMPLYING
WITH
98
WEIGHT­
PERCENT
REDUCTION
OF
TOTAL
ORGANIC
HAP
EMISSIONS
OR
A
LIMIT
OF
20
PARTS
PER
MILLION
BY
VOLUME
Control
Device
Parameters
to
be
Monitoreda
Recordkeeping
and
Reporting
Requirements
for
Monitored
Parameters
Thermal
Incinerator
Firebox
temperatureb
[
63.644(
a)(
1)(
i)]
1.
Continuous
recordsc
2.
Record
and
report
the
firebox
temperature
averaged
over
the
full
period
of
the
performance
test
­
NCSd
3.
Record
the
daily
average
firebox
temperature
for
each
operating
daye
4.
Report
all
daily
average
temperatures
that
are
outside
the
range
established
in
the
NCS
or
operating
permit
and
all
operating
days
when
insufficient
monitoring
data
are
collectedf
­
PRg
Catalytic
Incinerator
Temperature
upstream
and
downstream
of
the
catalyst
bed
[
63.644(
a)(
1)(
ii)]
1.
Continuous
records
2.
Record
and
report
the
upstream
and
downstream
temperatures
and
the
temperature
difference
across
the
catalyst
bed
averaged
over
the
full
period
of
the
performance
test
­
NCS
3.
Record
the
daily
average
upstream
temperature
and
temperature
difference
across
catalyst
bed
for
each
operating
daye
4.
Report
all
daily
average
upstream
temperatures
that
are
outside
the
range
established
in
the
NCS
or
operating
permit
­

PR
TABLE
5­
5
(
continued).

Control
Device
Parameters
to
be
Monitoreda
Recordkeeping
and
Reporting
Requirements
for
Monitored
Parameters
5.
Report
all
daily
average
temperature
differences
across
the
catalyst
bed
that
are
outside
the
range
established
in
the
NCS
or
operating
permit
­
PR
6.
Report
all
operating
days
when
insufficient
monitoring
data
are
collectedf
Boiler
or
Process
Heater
with
a
design
heat
input
capacity
less
than
44
megawatts
and
Vent
Stream
is
not
introduced
with
or
as
the
primary
fuelh,
i
Firebox
temperatureb
[
63.644(
a)(
4)]
1.
Continuous
records
2.
Record
and
report
the
firebox
temperature
averaged
over
the
full
period
of
the
performance
test
­
NCS
3.
Record
the
daily
average
firebox
temperature
for
each
operating
daye
4.
Report
all
daily
average
firebox
temperatures
that
are
outside
the
range
established
in
the
NCS
or
operating
permit
and
all
operating
days
when
insufficient
monitoring
data
are
collectedf
­
PR
TABLE
5­
5
(
continued).

Control
Device
Parameters
to
be
Monitoreda
Recordkeeping
and
Reporting
Requirements
for
Monitored
Parameters
Flare
Presence
of
a
flame
at
the
pilot
light
[
63.644(
a)(
2)]
1.
Hourly
records
of
whether
the
monitor
was
continuously
operating
and
whether
the
pilot
flame
was
continuously
present
during
each
hour
2.
Record
and
report
the
presence
of
a
flame
at
the
pilot
light
over
the
full
period
of
the
compliance
determination
­
NCS
3.
Record
the
times
and
durations
of
all
periods
when
a
pilot
flame
is
absent
or
the
monitor
is
not
operating
4.
Report
the
times
and
durations
of
all
periods
when
all
pilot
flames
of
a
flare
are
absent
­

PRAll
Control
DevicesPresence
of
flow
diverted
to
the
atmosphere
from
the
control
device
[
63.644(
c)(
1)]
or1.
Hourly
records
of
whether
the
flow
indicator
was
operating
and
whether
flow
was
detected
at
any
time
during
each
hour.

2.
Record
and
report
the
times
and
durations
of
all
periods
when
the
vent
stream
is
diverted
through
a
bypass
line
or
the
monitor
is
not
operating
­
PRMonthly
inspections
of
sealed
valves
[
63.644(
c)(
2)]
1.
Records
that
monthly
inspections
were
performed
2.
Record
and
report
all
monthly
inspections
Control
Device
Parameters
to
be
Monitoreda
Recordkeeping
and
Reporting
Requirements
for
Monitored
Parameters
NOTES:
aRegulatory
citations
are
listed
in
brackets.

bMonitor
may
be
installed
in
the
firebox
or
in
the
ductwork
immediately
downstream
of
the
firebox
before
any
substantial
heat
exchange
is
encountered.

c"
Continuous
records"
is
defined
in
§
63.641
of
this
subpart.

dNCS
=
Notification
of
Compliance
Status
described
in
§
63.652(
e)
of
this
subpart.

eThe
daily
average
is
the
average
of
all
recorded
parameter
values
for
the
operating
day.
If
all
recorded
values
during
an
operating
day
are
within
the
range
established
in
the
NCS
or
operating
permit,
a
statement
to
this
effect
can
be
recorded
instead
of
the
daily
average.

fWhen
a
period
of
excess
emission
is
caused
by
insufficient
monitoring
data,
as
described
in
§
63.552(
f)(
3)(
i)(
C)
of
this
subpart,
the
duration
of
the
period
when
monitoring
data
were
not
collected
shall
be
included
in
the
Periodic
Report.

gPR
=
Periodic
Reports
described
in
§
63.652(
f)
of
this
subpart.

hNo
monitoring
is
required
for
boilers
and
process
heaters
with
heat
input
capacities
>
44
megawatts
or
for
boilers
and
process
heaters
where
the
vent
stream
is
introduced
with
or
as
the
primary
fuel.
No
recordkeeping
or
reporting
associated
with
monitoring
is
required
for
such
boilers
and
process
heaters.

iProcess
vents
that
are
routed
to
refinery
fuel
gas
systems
are
not
regulated
under
this
subpart.
No
monitoring,
recordkeeping,
or
reporting
is
required
for
boilers
and
process
heaters
that
combust
refinery
fuel
gas.
102
103
6.0
ECONOMIC
IMPACTS
AND
SOCIAL
COSTS
The
goal
of
the
RIA
is
to
evaluate
the
potential
benefits
and
costs
of
specific
pollution
control
standards
on
our
nation's
economy.
Potential
regulatory
benefits
relate
to
reduced
HAP
and
VOC
emissions
that
have
detrimental
effects
on
the
health
and
well­
being
of
members
of
society.
Social
costs
associated
with
the
regulation
are
those
costs
borne
by
consumers
and
producers
of
refined
petroleum
products
and
by
society
at
large
as
a
result
of
the
proposed
standards.
A
comparison
of
the
costs
and
benefits
or
net
benefits
(
social
benefits
less
social
costs)
of
alternative
control
measures
serves
as
a
basis
for
rational
and
effective
environmental
policymaking.

The
emission
control
measures
considered
in
this
analysis
will
require
domestic
petroleum
refineries
to
incur
increased
investment
costs
for
control
equipment
and
the
associated
annual
operation
and
maintenance
expenses.
Increased
costs
of
production
may
impact
the
domestic
petroleum
refining
market
in
a
number
of
ways.
Primary
market
impacts
resulting
from
the
control
measures
include
increases
in
the
market
equilibrium
price
for
refined
petroleum
products,
decreases
in
output
levels
for
products
produced
and
sold
nationally,
changes
in
the
value
of
domestic
shipments
or
revenues
for
refineries
in
the
industry,

and
possible
plant
closures.
Predicted
changes
in
the
market
equilibrium
price
and
quantity
of
refined
petroleum
products
produced
and
sold
will
result
in
additional
market
modifications
or
secondary
market
impacts.
The
secondary
effects
relate
to
the
likely
labor
market
adjustments
(
job
losses),
energy
input
market
changes
(
decrease
in
the
energy
used
as
an
input
in
the
production
of
petroleum
products)
and
foreign
trade
effects
(
decrease
in
net
exports).
Control
measures
may
also
have
a
104
detrimental
influence
on
the
capital
availability
and
financial
position
of
firms
in
the
petroleum
refining
industry.
Welfare
changes
for
consumers,
producers,
and
society
at
large
or
the
social
costs
of
the
proposed
emission
controls
will
also
be
evaluated.
Additionally,
the
Regulatory
Flexibility
Act
(
RFA)

requires
that
an
assessment
be
made
of
the
effect
of
control
measures
on
small
entities.

This
chapter
will
briefly
describe
the
methods
used
to
estimate
the
primary
impacts,
secondary
effects,
and
small
business
impacts
of
the
emission
controls
on
the
petroleum
refining
industry.
A
more
detailed
description
of
the
methods
used
in
the
analysis
is
available
in
the
Economic
Impact
Analysis
of
the
Petroleum
Refinery
NESHAP
(
1994).
A
profile
of
the
petroleum
refining
industry,
the
primary
market
impacts,
capital
availability
consequences,
secondary
market
impacts,
small
business
impacts,
and
social
costs
of
the
control
measures
will
be
presented
in
this
chapter.

6.1
PROFILE
OF
THE
PETROLEUM
REFINING
INDUSTRY
The
petroleum
industry
can
be
divided
into
five
distinct
sectors:
(
1)
exploration,
(
2)
production,
(
3)
refining,
(
4)

transportation,
and
(
5)
marketing.
Refining,
the
process
subject
to
this
NESHAP,
is
the
process
which
converts
crude
oil
into
useful
fuels
and
other
products
for
consumers
and
industrial
users.
The
Standard
Industrial
Classification
(
SIC)
code
for
all
petroleum
refineries
is
2911.
Although
petroleum
refineries
produce
a
diverse
slate
of
products,
the
five
primary
output
categories
are
(
1)
motor
gasoline,
(
2)
jet
fuel,
(
3)
residual
fuel,
(
4)
distillate
fuel,
and
(
5)
liquefied
petroleum
gases
(
LPGs),
which
in
total
accounted
for
93
percent
of
all
domestically
refined
petroleum
products
in
1992.
This
analysis
is
concerned
only
with
these
five
main
product
categories.

It
should
be
noted
that
the
economic
impact
analysis
reflects
the
compliance
costs
from
the
proposal.
Thus
the
actual
impacts
are
smaller
than
estimated
here,
though
only
by
a
minor
amount.
105
A
brief
overview
of
the
petroleum
refining
industry
is
presented
in
this
section.
Economic
and
financial
data
which
characterize
conditions
in
the
refining
industry
and
that
are
likely
to
influence
the
economic
impacts
associated
with
the
implementation
of
the
alternative
NESHAPs
are
discussed.
The
information
in
this
section
represents
the
data
inputs
to
the
economic
model
used
in
the
EIA.
More
details
concerning
the
industry
are
provided
in
the
Economic
Impact
Analysis
of
the
Petroleum
Refinery
NESHAP
(
1995)
and
Industry
Profile
of
the
Petroleum
Refinery
NESHAP
(
1993).

6.1.1
Profile
of
Affected
Facilities
A
brief
description
of
the
facilities
affected
by
the
proposed
emission
controls
is
presented
in
this
section.
The
processes
and
product
market
characteristics
of
the
petroleum
refining
industry
are
discussed.
Refineries
subject
to
the
regulations
are
identified
by
geographical
location,
capacity,
and
complexity.

6.1.1.1
General
Process
Description.
The
refining
process
transforms
crude
oil
into
a
wide
range
of
petroleum
products
which
have
a
variety
of
applications.
The
refining
industry
has
developed
a
complex
variety
of
production
processes
used
to
transform
crude
oil
into
its
various
final
forms,
many
of
which
are
already
subject
to
some
CAA
controls.

There
are
numerous
refinery
processes
from
which
HAP
emissions
occur.
Separation
processes
(
such
as
atmospheric
distillation
and
vacuum
distillation),
breakdown
processes
(
thermal
cracking,

coking,
visbreaking),
change
processes
(
catalytic
reforming,

isomerization),
and
buildup
processes
(
alkylation
and
polymerization)
all
have
the
potential
to
emit
HAPs.
HAP
emissions
may
occur
through
process
vents,
equipment
leaks,
or
from
evaporation
from
storage
tanks
or
wastewater
streams.
The
NESHAP
will
address
emissions
from
all
of
these
refinery
emission
points.

6.1.1.2
Product
Description
and
Differentiation.
Most
petroleum
refinery
output
consists
of
motor
gasoline
and
other
types
of
fuel,
but
some
non­
fuel
uses
exist,
such
as
106
petrochemical
feedstocks,
waxes,
and
lubricants.
The
output
of
each
refinery
is
a
function
of
its
crude
oil
feedstock
and
its
preferred
petroleum
product
slate.

Motor
gasoline
is
defined
as
a
complex
mixture
of
relatively
volatile
hydrocarbons
that
has
been
blended
to
form
a
fuel
suitable
for
use
in
spark­
ignition
engines.
Residual
fuel
oil
is
a
heavy
oil
which
remains
after
the
distillate
fuel
oils
and
lighter
hydrocarbons
are
distilled
away
in
refinery
operations.

Uses
include
fuel
for
steam­
powered
ships,
commercial
and
industrial
heating,
and
electricity
generation.
Distillate
fuel
oil
is
a
general
classification
for
one
of
the
petroleum
fractions
produced
in
conventional
distillation
operations.
It
is
used
primarily
for
space
heating,
on­
and
off­
highway
diesel
engine
fuel
(
including
railroad
engine
fuel
and
fuel
for
agricultural
machinery),
and
electric
power
generation.
Jet
fuel
is
a
low
freezing
point
distillate
of
the
kerosene
type
used
primarily
for
turbojet
and
turboprop
aircraft
engines.
LPGs
are
defined
as
ethane,
propane,
butane,
and
isobutane
produced
at
refineries.

Product
differentiation
is
a
form
of
non­
price
competition
used
by
firms
to
target
or
protect
a
specific
market.
The
extent
to
which
product
differentiation
is
effective
depends
on
the
nature
of
the
product.
The
more
homogenous
the
overall
industry
output,
the
less
effective
differentiation
by
individual
firms
becomes.
Each
of
the
five
petroleum
products
in
this
analysis
are
by
nature
quite
homogenous
C
there
is
little
difference
between
Exxon
premium
gasoline
and
Shell
premium
gasoline
C
and,

as
a
result,
differentiation
does
not
play
a
major
role
in
the
competitiveness
among
petroleum
refineries.

6.1.1.3
Distinct
Market
Characteristics.
The
markets
for
refined
petroleum
products
vary
by
geographic
location.
Regional
markets
may
differ
due
to
the
quality
of
crude
supplied
or
the
local
product
demand.
Some
smaller
refineries
which
produce
only
one
product
have
single,
local
markets,
while
larger,
more
complex
refineries
have
extensive
distribution
systems
and
sell
their
output
in
several
different
regional
markets.
In
addition,
107
because
refineries
are
the
source
of
non­
hydrocarbon
pollutants
such
as
individual
HAPs,
volatile
organic
compounds
(
VOCs),

sulfur
dioxide
(
SO
2),
and
nitrogen
oxide
(
NO
x),
many
Federal,

State,
and
local
regulations
are
already
in
place
in
some
locations.
Differences
in
the
regional
market
structure
may
also
result
in
different
import/
export
characteristics.

The
United
States
is
segmented
into
five
regions,
called
Petroleum
Administration
for
Defense
Districts
(
PADDs),
for
which
statistics
are
maintained.
PADDs
were
initiated
in
the
1940s
for
the
purpose
of
dividing
the
United
States
into
five
economically
and
geographically
distinct
regions.
Relatively
independent
markets
for
petroleum
products
exist
in
each
PADD.

In
addition
to
differences
in
regional
markets,
each
of
the
five
product
categories
in
this
analysis
possesses
its
own
individual
market
segment,
satisfying
demand
among
different
enduse
sectors.
The
substitutability
of
one
of
the
products
C
motor
gasoline,
for
example
C
is
not
possible
with
another
refinery
output,
such
as
jet
fuel.
Thus,
each
of
the
products
in
this
analysis
is
treated
as
a
separate
product
with
its
own
share
of
the
market.
From
a
refinery
standpoint,
however,
if
the
production
of
one
refined
product
were
to
become
less
costly
after
regulation,
production
of
this
product
may
increase
at
the
expense
of
a
product
with
a
more
costly
refining
process.

6.1.1.4
Affected
Refineries
and
Employment.
There
are
currently
192
operable
petroleum
refineries
in
the
United
States.
1
Though
refineries
differ
in
capacity
and
complexity,

almost
all
refineries
have
some
atmospheric
distillation
capacity
and
additional
downstream
charge
capacity.
Most
of
the
employment
in
the
industry
exists
at
larger
refineries.
Slightly
fewer
than
4
percent
of
refinery
employees
work
in
establishments
of
fewer
than
100
people,
and
the
remaining
96
percent
of
the
labor
force
in
the
industry
works
at
establishments
of
100
employees
or
more.

6.1.1.5
Capacity
and
Capacity
Utilization.
Refineries
have
many
different
specialties,
targeted
product
slates,
and
capabilities.
Some
refineries
produce
output
only
by
processing
crude
oil
through
basic
atmospheric
distillation.
These
108
refineries
have
very
little
ability
to
alter
their
product
yields
and
are
deemed
to
have
low
complexity.
In
contrast,
refineries
that
have
assorted
downstream
processing
units
can
substantially
improve
their
control
over
yields,
and
thus
have
a
higher
level
of
complexity.
Because
of
their
differences
in
size
and
complexity,
refineries
can
be
grouped
by
two
main
structural
features:
(
1)
atmospheric
distillation
capacity
(
which
denotes
their
size)
and
(
2)
process
complexity
(
which
characterizes
the
type
of
products
a
refinery
is
capable
of
producing).

Capacity
utilization
rates
of
petroleum
refineries
have
been
rising
in
recent
years,
reaching
a
high
of
92
percent
in
1991.2
This
indicates
that
existing
refineries
are
operating
closer
to
full
capacity
than
in
the
past,
and
will
have
limited
opportunity
to
enhance
production
by
increasing
utilization.

During
the
past
23
years,
the
entire
domestic
refining
industry
has
been
affected
by
crude
oil
quantity
changes
and
shifting
petroleum
demand
patterns.
A
more
complex
and
flexible
refining
industry
has
evolved
domestically.
Ownership
of
U.
S.

refineries
has
changed
through
consolidation
and
foreign
investments.
Throughout
the
1970s,
the
number
of
U.
S.
refineries
rose
rapidly
in
response
to
rising
demand
for
petroleum
products.

In
the
early
1980s,
the
petroleum
refining
industry
entered
a
period
of
restructuring,
which
continued
through
1992.
A
record
number
of
U.
S.
refineries
were
operating
in
1981.
A
decline
in
petroleum
demand
in
the
early
1980s
caused
many
small
refineries
and
older,
inefficient
plants
to
close.
The
refinery
shutdowns
resulted
in
improved
operating
efficiency,
which
enabled
the
refinery
utilization
rate
to
increase,
despite
lower
crude
oil
inputs.
Operable
capacity
has
remained
relatively
constant
since
1985,
while
capacity
utilization
has
risen
steadily.

6.1.1.6
Refinery
Complexity.
Complexity
is
a
measure
of
the
different
processes
used
in
refineries.
It
can
be
quantified
by
relating
the
complexity
of
a
downstream
process
with
atmospheric
distillation,
where
atmospheric
distillation
is
assigned
the
lowest
value,
1.0.
The
level
of
complexity
of
a
refinery
generally
correlates
to
the
types
of
products
the
refinery
is
capable
of
producing.
Higher
complexity
denotes
a
greater
109
ability
to
enhance
or
diversify
product
output,
to
improve
yields
of
preferred
products,
or
to
process
lower
quality
crude.
By
defining
refinery
complexity,
it
is
possible
to
differentiate
among
refineries
having
similar
capacities
but
different
process
capabilities.
In
theory,
more
complex
refineries
are
more
adaptable
to
change,
and
are
therefore
potentially
less
affected
by
regulation.
The
complexity
of
a
refinery
usually
increases
as
its
crude
capacity
increases.
(
Lube
plants
are
the
exception
to
this
rule.)
Over
50
percent
of
the
operable
capacity
(
50,000
to
100,000
bbl/
d)
can
be
found
at
refineries
with
above­
average
complexity.
Likewise,
the
smaller
refineries
are
less
complex.

6.1.2
Market
Structure
The
market
structure
of
an
industry
will
influence
the
magnitude
of
market
impacts
resulting
from
emission
controls.
A
perfectly
competitive
market
is
characterized
by
many
sellers,
no
barriers
to
entry
or
exit,
homogeneous
output,
and
complete
information.
A
perfectly
competitive
market
is
one
in
which
producers
have
small
degrees
of
market
power
and
pricing
is
determined
by
market
forces,
rather
than
by
the
producers.

Alternatively
an
industry
with
monopoly
power
has
more
discretion
over
the
market
price
charged.
Producers
in
such
an
industry
have
greater
market
power.
A
profile
of
the
market
structure
of
the
petroleum
refining
industry
is
provided
in
the
following
sections,
including
an
assessment
of
the
number
of
domestic
operating
refineries,
the
market
concentration,
and
the
extent
of
vertical
integration,
and
diversification.

6.1.2.1
Market
Concentration.
Market
concentration
is
a
measure
of
the
output
of
the
largest
firms
in
the
industry,

expressed
as
a
percentage
of
total
national
output.
Market
concentration
is
usually
measured
for
the
4,
8,
or
20
largest
firms
in
the
industry.
A
firm's
concentration
in
a
market
provides
some
indication
of
the
firm's
size
distribution.
For
example,
on
one
extreme,
a
concentration
of
100
percent
would
indicate
monopoly
control
of
the
industry
by
one
firm.
On
the
other
extreme,
concentration
of
less
than
1
percent
would
indicate
the
industry
was
comprised
of
numerous
small
firms.

Concentration
is
measured
based
on
refining
capacity.
Until
110
recently,
the
top
four
firms
in
the
refining
industry
have
consistently
comprised
over
30
percent
of
the
market
share,
but
most
market
concentration
ratios
have
marginally
decreased
in
recent
years.

Market
concentration
may
also
be
evaluated
using
the
Herfindahl­
Hirschman
index,
which
is
defined
as
the
sum
of
the
squared
market
shares
(
expressed
as
a
percentage)
for
all
firms
in
the
industry.
If
a
monopolist
existed,
with
market
share
equal
to
100
percent,
the
upper
limit
of
the
index
(
10,000)
would
be
attained.
If
an
infinite
number
of
small
firms
existed,
the
index
would
equal
zero.
An
industry
is
considered
unconcentrated
if
the
Herfindahl­
Hirschman
index
is
less
than
1,000.
Ratings
are
also
developed
for
moderately
concentrated
(
between
1,000
and
1,800)
and
highly
concentrated
(
greater
than
1,800)
industries.

The
petroleum
refining
Herfindahl­
Hirschman
index
in
recent
years
has
been
less
than
500.
Thus
the
refining
industry
is
considered
unconcentrated.
3
6.1.2.2
Industry
Integration
and
Diversification.
Vertical
integration
exists
when
the
same
firm
supplies
input
for
several
stages
of
the
production
and
marketing
process.
Firms
that
operate
petroleum
refineries
are
vertically
integrated
because
they
are
responsible
both
for
exploration
and
production
of
crude
oil
(
which
supplies
the
input
for
refineries)
and
for
marketing
the
finished
petroleum
products
after
refining
occurs.
To
assess
the
level
of
vertical
integration
in
the
industry,
firms
are
generically
classified
as
major
or
independent.
Generally
speaking,
major
energy
producers
are
defined
as
firms
that
are
vertically
integrated.
There
are
currently
20
major
energy
companies.
The
crude
capacity
of
the
major,
vertically
integrated
firms
represents
almost
70
percent
of
nationwide
production.

For
the
major
oil
companies,
horizontal
integration
exists
because
these
firms
operate
several
refineries
which
are
often
distributed
around
the
nation.
Seventy­
three
of
the
109
firms
in
the
industry
operate
only
one
refinery
each.
These
are
the
smaller
independent
firms.
The
major
firms
operate
several
refineries,
and
the
largest,
Chevron,
operates
13.
Fourteen
firms
operate
four
or
more
refineries
each.
111
Diversification
exists
when
firms
produce
a
wide
array
of
unrelated
products.
In
the
short
run,
diversification
may
indirectly
benefit
firms
that
engage
in
petroleum
refining,
since
the
costs
of
control
in
petroleum
refining
may
be
dispersed
over
other
unaffected
businesses
operated
by
the
firm.
Over
the
long
term,
however,
firms
will
not
subsidize
petroleum
product
production
with
profit
from
other
operations,
but
will
shut
down
unprofitable
operations
instead.
Diversification
within
the
energy
industry
may
mitigate
some
of
the
effects
of
regulation
at
least
in
the
short
run.

6.1.2.3
Financial
Profile.
The
financial
performance
of
firms
in
the
petroleum
refining
industry
is
particularly
relevant
to
an
evaluation
of
the
impact
of
regulation
on
the
industry.
In
order
to
evaluate
the
financial
condition
of
the
refinery
operations
of
firms,
a
sample
of
the
petroleum
refining
industry's
major
firms
financial
operations
were
evaluated.

Annual
reports
to
stockholders
were
used
as
a
source
of
data
for
the
analysis.
While
this
sample
is
too
small
and
diverse
to
be
considered
representative
of
the
aggregate
industry,
the
data
presented
are
more
recent
and
more
refinery­
specific
than
American
Petroleum
Institute
data.

The
sample
of
annual
report
data
analyzes
refinery­
specific
data
in
order
to
provide
a
preliminary
assessment
of
the
financial
condition
of
firms
in
the
industry.
This
12­
firm
sample
as
a
whole
operated
59
refineries
in
1991,
and
represented
45.3
percent
of
the
industry's
total
refining
capacity.
Refining
capacity
in
the
sample
ranges
from
165,000
bbl/
d
to
2,139,000
bbl/
d.
Over
the
5­
year
period
from
1987
to
1991,
operating
income
per
dollar
of
revenue
increased
from
1
percent
to
4
percent.
Capital
expenditures
increased
steadily,
while
refined
product
sales
continued
a
period
of
decline.
The
consolidation
taking
place
in
the
refining
industry
is
reflected
in
the
decreasing
crude
oil
capacity
and
refinery
runs.

Refined
product
margins
are
a
good
indicator
of
overall
refinery
financial
performance.
4
The
difference
between
refined
product
costs
and
refined
product
revenues
is
the
refined
product
margin.
During
the
1980s,
refined
product
margins
were
affected
112
by
a
shift
in
product
slates
to
gasoline
and
jet
fuels,
the
decrease
in
crude
oil
prices,
fluctuations
in
demand,
and
an
increase
in
refinery
utilization
rates.
5
In
constant
1982
dollars,
the
refined
product
margin
fluctuated
over
this
time
frame,
decreasing
between
1985
and
1987
and
then
increasing
significantly
in
1988.
The
fluctuations
in
the
refined
product
margins
reflect
the
volatility
of
the
market
and
the
degree
to
which
refineries'
revenues
are
often
subject
to
significant
change
over
short
time
periods.
In
the
early
half
of
1990,
the
margin
between
overall
U.
S.
refined
product
prices
and
crude
oil
import
costs
rose
to
record
levels,
given
falling
crude
oil
prices
and
stable
gasoline
prices.
6
After
the
invasion
of
Kuwait,
U.
S.
refined
product
prices
did
not
keep
pace
with
crude
oil
prices
for
the
remainder
of
the
year.
This
negatively
impacted
refinery
revenues
for
1991.

Firms
have
three
sources
of
funding
for
the
capital
necessary
to
purchase
emission
control
equipment
required
by
the
NESHAP.

These
sources
include
(
1)
internal
funds,
(
2)
borrowed
funds,

and
(
3)
stock
issues.
Typically,
firms
seek
a
balance
between
the
use
of
debt
and
stock
issues
for
financing
investments.

Debt­
to­
equity
ratios
reflect
a
measure
of
the
extent
to
which
the
firm
has
balanced
the
tax
advantages
of
borrowing
with
the
financial
safety
of
stockholder
financing.
Based
on
information
obtained
in
the
annual
reports
of
the
12
companies
in
the
refinery
sample,
firms
anticipate
that
internally
generated
funds
will
fund
most
of
their
capital
expenditures.
Other
firms
recognize
the
need
to
also
draw
on
available
credit
lines
and
commercial
paper
borrowing.
Overall,
capital
expenditures
of
refiners
have
doubled
since
1977,
although
spending
peaked
in
1982
and
has
since
been
in
a
period
of
decline.

Planned
uses
of
investment
funds
by
the
12
firms
in
the
financial
sample
over
the
next
few
years
include
construction
of
diesel
desulfurization
units,
expansion
of
existing
units,
and
construction
of
units
to
manufacture
methyl
tertiary
butyl
ether
(
MTBE)
and
oxygenated
fuels.
In
a
1991
study,
Cambridge
Energy
Research
Associates
(
CERA)
surveyed
refiners
and
oxygenate
producers
to
evaluate
the
ability
of
the
refining
industry
to
113
meet
CAA
provisions.
7
Among
the
firms
in
the
CERA
survey,
the
majors
and
some
large
independents
plan
to
fund
their
investments
primarily
or
entirely
from
internally
generated
cash
flows,
while
most
of
the
small
refineries
surveyed
are
planning
on
resorting
to
the
debt
market
for
funds.

6.1.3
Market
Supply
Refiners
have
increased
production
of
most
refined
products
almost
every
year
since
1984.
Historically,
motor
gasoline
has
been
the
product
that
is
supplied
in
the
greatest
quantities
to
meet
increased
demand.
Most
of
the
other
petroleum
products
show
a
modest
net
increase
in
supply
over
the
past
few
years.
The
lack
of
significant
change
in
the
yield
for
most
refined
petroleum
products
indicates
a
relatively
stable
supply
slate,

but
significant
regulatory
costs
could
force
some
reshuffling
of
product
yield.

Refinery
production
of
motor
gasoline
has
increased
each
year,

with
the
exception
of
periods
of
economic
recession.
Production
remained
relatively
steady
from
1988
to
1992.
Distillate
fuel
oil
output
peaked
at
3.3
million
barrels
per
day
in
1977,
then
fell
through
1983.
Output
has
increased
slightly
almost
every
year
since,
reaching
3
million
barrels
per
day
in
1992.
Jet
fuel
production
grew
during
the
1970s
and
1980s,
and
almost
doubled
by
1990
before
declining
to
1.4
million
barrels
per
day
in
1992.

Residual
fuel
oil
production
generally
declined
from
1980
through
1985,
and
was
1
million
barrels
per
day
in
1992,
compared
to
0.7
million
barrels
per
day
in
1970.

6.1.3.1
Supply
Determinants.
The
most
important
short­
run
production
decision
for
an
oil
refinery
is
the
determination
of
how
much
crude
oil
to
allocate
for
the
production
of
each
of
the
refinery's
products.
The
production
decision
depends
on
the
profit
each
of
the
oil
products
can
generate
for
the
firm.

Profits,
in
turn,
depend
on
the
productivity
of
the
oil
refinery
C
its
ability
to
produce
each
oil
product
as
effectively
as
possible
from
a
barrel
of
crude
oil.
The
quantity
of
crude
oil
a
refinery
will
refine
depends
on
the
capacity
of
the
refinery
and
the
cost
of
production.
The
marginal
costs
of
production
of
each
product
will
determine
any
future
changes
in
production.
Crude
114
oil
is
the
primary
material
input
to
the
refining
process;
as
a
result,
the
production
of
refined
products
is
vulnerable
to
fluctuations
in
the
world
crude
oil
market.

In
the
long
run,
production
decisions
are
based
on
the
cost
of
capacity
expansion
relative
to
existing
price
levels
and
expected
future
price
levels.
A
refinery
uses
different
processing
units
to
turn
crude
oil
into
finished
products,
so
when
a
particular
processing
unit
reaches
capacity,
output
can
be
increased
only
by
substituting
a
more
expensive
process.
Firms
will
typically
utilize
sufficient
crude
oil
to
fill
the
appropriate
processing
unit
until
the
price
increases
substantially.
At
this
point,
the
firm
would
calculate
whether
the
increased
price
warrants
using
an
additional,
more
expensive
processing
unit.
8
6.1.3.2
Exports
of
Petroleum
Products.
Some
measure
of
the
extent
of
foreign
competition
can
be
obtained
by
comparing
exports
to
domestic
production.
Export
levels
and
domestic
refinery
output
for
the
past
decade
were
analyzed.
Exports
as
a
percentage
of
domestic
refinery
output
steadily
increased
from
1984
to
1991
and
then
fell
slightly
to
5.6
percent
in
1992.

Distillate
oil,
residual
fuel
oil,
motor
gasoline,
and
petroleum
coke
are
exported
in
the
highest
volumes.
The
combined
export
volumes
of
these
products
represent
75
percent
of
domestic
refinery
output
shipped
overseas.

6.1.4
Market
Demand
Characteristics
The
end­
use
sectors
that
contribute
to
demand
for
refined
petroleum
products
are
classified
in
the
following
four
economic
sectors:
(
1)
household
and
commercial,
(
2)
industrial,
(
3)

transportation,
and
(
4)
electric
utilities.
Petroleum
products
used
as
transportation
fuel
include
motor
gasoline,
distillate
(
diesel)
fuel,
and
jet
fuel,
and
accounted
for
an
estimated
64
percent
of
all
U.
S.
petroleum
demand
in
1990.
Since
mobile
source
emissions
will
be
regulated
by
Title
II
regulations,
this
output
from
petroleum
refineries
will
be
most
affected
by
the
CAA.
The
industrial
sector
constitutes
the
second
highest
percentage
of
demand
for
petroleum
products,
followed
by
household
and
electric
utility
demands.
115
Petroleum
is
used
most
widely
in
the
transportation
sector.

In
the
household
and
commercial
sector,
light
heating
oil
and
propane
are
used
for
heating
and
energy
uses,
and
compete
with
natural
gas
and
electricity.
Petroleum
fuels
in
the
industrial
sector
compete
with
natural
gas,
coal,
and
electricity.
In
the
industrial
sector,
residual
and
distillate
heating
oils
are
used
for
boiler
and
power
fuel.
In
the
electric
utility
sector,

petroleum
products
supply
energy
in
the
form
of
heavy
residual
fuel
oil
and
smaller
amounts
of
bulk
light
distillate
fuel
oil.
9
In
terms
of
refined
products,
the
motor
gasoline
and
jet
fuel
markets
are
associated
with
the
transportation
sector.
The
markets
for
distillate
fuel
oil
are
associated
with
the
transportation
sector
(
diesel
engine
fuel
as
a
trucking
fuel),

household
(
space
heating),
industrial
(
fuel
for
commercial
burner
installations),
and
electric
utilities
(
power
generation).
The
sectors
that
are
sources
of
demand
for
residual
fuel
oil
include
the
commercial
and
industrial
sectors
(
heating),
utilities
(
electricity
generation),
and
the
transportation
sector
(
fuel
for
ships).
Nonutility
use
of
residual
fuel
has
been
decreasing
due
to
interfuel
substitution
in
the
commercial
and
industrial
sectors.
Because
LPGs
cover
a
broad
range
of
gases,
demand
levels
are
attributable
to
various
end
users.

6.1.4.1
Demand
Determinants.
The
demand
for
refined
petroleum
products
is
primarily
determined
by
price
level,
the
price
of
available
substitutes,
and
economic
growth
trends.
The
degree
to
which
price
level
influences
the
quantity
of
petroleum
products
demanded
is
referred
to
as
the
price
elasticity
of
demand,
which
is
explored
later
in
this
report.
Prices
of
refined
petroleum
products
affect
the
willingness
of
consumers
to
choose
petroleum
over
other
fuels,
and
may
ultimately
cause
a
change
in
consumer
behavior.
In
the
transportation
sector,
the
effect
of
high
gasoline
prices
on
fuel
use
could
reduce
discretionary
driving
in
the
short
term
and,
in
the
long
term,

result
in
the
production
of
more
fuel­
efficient
vehicles.

In
the
market
for
jet
fuel,
demand
is
primarily
determined
by
a
combination
of
price
concerns
and
the
overall
health
of
the
airline
industry.
In
the
residential
sector,
demand
for
home
116
heating
(
distillate)
is
determined
in
part
by
price
level,
and
also
by
temperature
levels
and
climate.
Temperature
in
different
areas
of
the
country
may
determine
the
degree
to
which
buildings
and
houses
are
insulated.
Temperature
and
insulation
are
exogenous
factors
which
will
determine
heating
needs
regardless
of
the
price
level
of
fuel.
High
prices
for
home
heating
oil
provide
incentive
for
individuals
to
conserve
by
adjusting
thermostats,
improving
insulation,
and
by
using
energy­
efficient
appliances.
In
some
cases,
higher
oil
prices
also
provide
incentive
for
switching
to
natural
gas
or
electric
heating.

(
Adjusting
thermostats
is
a
short­
run
response,
while
changing
to
more
energy­
efficient
appliances
or
fuels
are
long­
run
responses.)

In
the
industrial
sector,
fuel
oil
competes
with
natural
gas
and
coal
for
the
boiler­
feed
market.
High
prices
relative
to
other
fuels
tend
to
encourage
fuel­
switching,
especially
at
electric
utilities
and
in
industrial
plants
having
dual­
fired
boilers.
Generally
speaking,
in
choosing
a
boiler
for
a
new
plant,
management
must
choose
between
the
higher
capital/
lower
operating
costs
of
a
coal
unit
or
the
lower
capital/
higher
operating
costs
of
a
gas­
oil
unit.
In
the
utility
sector,
most
new
boilers
in
the
early
1980s
were
coal­
fired
due
to
the
impact
of
legislative
action,
favorable
economic
conditions,
and
longterm
assured
supplies
of
coal.
10
Today,
because
the
CAA
will
require
utilities
to
scrub
or
use
a
low­
sulfur
fuel,
oil
will
eventually
become
more
competitive
with
coal
as
a
boiler
fuel,

although
a
significant
increase
in
oil­
fired
capacity
is
not
expected
until
2010.11
Demand
levels
in
each
of
the
end­
use
sectors
are
also
affected
by
the
economic
environment.
Periods
of
economic
growth
and
periods
of
increased
demand
for
petroleum
products
typically
occur
simultaneously.
For
example,
in
an
expanding
economy,
more
fuel
is
needed
to
transport
new
products,
to
operate
new
production
capacity,
and
to
heat
new
homes.
Conversely,
in
periods
of
low
economic
growth,
demand
for
petroleum
products
decreases.
117
6.1.4.2
Past
and
Present
Consumption.
Total
consumption
of
all
types
of
petroleum
products
has
fluctuated
over
the
past
20
years,
reflecting
the
volatility
of
this
market.
The
consumption
level
has
been
sporadic
and
has
shown
an
overall
decline
in
recent
years.
Demand
for
individual
petroleum
product
types
has
also
fluctuated
over
this
period.
The
percentage
of
total
demand
is
highest
for
motor
gasoline
followed
by
demand
for
distillate
fuel
oil.
Over
the
23­
year
period
from
1970
to
1992,
the
demand
for
residual
fuel
oil
has
decreased
by
50
percent,
showing
the
greatest
percentage
of
change
over
time
of
any
of
the
petroleum
products.
It
has
also
been
the
only
fuel
to
show
a
decline
in
use.
This
decrease
in
residual
fuel
demand
reflects
a
move
in
the
industry
from
heavier
fuels
toward
lighter,
more
refined
versions.
This
trend
is
expected
to
continue
into
the
future
as
efforts
to
control
air
emissions
go
into
effect.

All
other
types
of
fuel
show
increases
in
use,
with
the
most
growth
occurring
in
the
market
for
jet
fuel.
Substantial
gains
in
airplane
fuel
efficiency
in
the
last
two
decades,
which
have
resulted
from
improved
aerodynamic
design
and
a
shift
toward
higher
seating
capacities,
have
been
exceeded
by
even
faster
growth
in
passenger
miles
traveled.
12
The
other
categories
show
an
average
growth
rate
of
approximately
23
percent
over
this
time
period.
All
major
petroleum
products
registered
lower
demand
in
1991
than
in
1990,
except
LPGs.
This
was
the
first
time
since
1980
that
demand
for
all
major
petroleum
products
fell
simultaneously
in
the
same
year.
In
this
case,
decreased
demand
was
brought
on
by
warmer
winter
temperatures,
an
economic
slowdown,
and
higher
prices
resulting
from
the
Persian
Gulf
situation.
13
Motor
gasoline
demand
increased
from
a
1970
low
to
a
high
of
7.4
million
barrels
per
day
in
1978.
The
increase
reflected
a
31
percent
growth
in
the
number
of
automobiles
in
use
and
a
25
percent
growth
in
vehicle
miles
traveled.
From
1985
to
1992,

motor
gasoline
use
accounted
for
about
42
percent
of
all
petroleum
products
consumed.

Changes
in
demand
for
distillate
fuel
oil
were
similar
to
motor
gasoline
in
that
consumption
reached
its
lowest
and
highest
118
levels
in
1970
and
1978,
respectively.
Between
1985
and
1992,

consumption
was
relatively
stable
and
accounted
for
about
18
percent
of
total
U.
S.
petroleum
consumption.
Residual
fuel
oil
demand,
in
response
to
lower­
priced
natural
gas
and
other
factors,
fell
64
percent,
from
a
high
in
1977
of
3.1
million
barrels
per
day
to
1.1
million
barrels
per
day
in
1992.

Between
the
period
from
1970
to
1990,
expanding
air
travel
spurred
a
57
percent
growth
in
jet
fuel
demand.
Demand
increased
from
a
1970
low
of
1.0
million
barrels
per
day
to
1.5
million
barrels
per
day
in
1990.

The
variation
in
U.
S.
petroleum
product
demand
has
been
linked
to
changes
in
the
prices
of
petroleum
products
relative
to
one
another,
and
relative
to
other
energy
sources.
Dramatic
petroleum
price
increases
and
eventual
steep
drops
were
in
response
to
wars,
political
upheaval
in
crude
oil
producing
areas,
and
supply
disruptions
during
the
past
two
decades.

During
this
period,
the
more
stable
and
lower
prices
of
alternative
fuels
led
consumers
to
switch
from
petroleum
as
their
fuel
of
economic
choice.

6.1.4.3
Imports
of
Refined
Petroleum
Products.
Imports
as
a
percentage
of
domestic
consumption
have
fluctuated
during
the
period
1981
through
1992,
although
in
1992
levels
were
10.6
percent,
or
roughly
the
same
level
as
in
1981.
The
import
to
export
ratio
has
decreased
since
1981,
due
primarily
to
steady
increases
in
exports.

6.1.4.4
Pricing.
Prices
for
petroleum
products
have
shown
volatility
over
the
time
period
from
1978
through
1992.
This
volatility
is
mainly
attributable
to
the
fluctuations
in
the
global
market
for
crude
oil
and
the
inelastic
demand
for
petroleum
products.
Inelastic
demand
allows
refiners
to
pass
crude
oil
price
increases
on
to
consumers.
Since
petroleum
products
are
essentially
commodity
products
and
are
produced
by
a
large
number
of
refineries,
refineries
have
little
ability
to
differentiate
products
or
their
prices.

6.1.5
Market
Outlook
Quantitative
production,
demand,
and
price
projections
are
available
from
the
literature.
Projections
are
important
to
the
119
economic
impact
analysis
since
future
market
conditions
contribute
to
the
potential
impacts
of
the
NESHAP
which
are
assessed
for
the
fifth
year
after
regulation.

6.1.5.1
Supply
Outlook
(
Production
and
Capacity).
The
refining
industry
was
operating
near
maximum
capacity
in
1991,

with
an
average
annual
utilization
rate
of
approximately
92
percent.
14
This
is
an
increase
from
levels
of
previous
years.

In
the
market
for
motor
gasoline,
for
example,
production
capacity
is
nearly
at
full
capacity.
As
a
result,
any
increases
in
demand
will
have
to
be
met
by
imported
products.
This
will
result
in
an
increase
in
worldwide
competition
for
gasoline.

East
Coast
refiners,
accounting
for
more
than
90
percent
of
all
unleaded
gas
imports
to
the
United
States,
will
be
most
affected
by
this
increased
competition.
15
DOC
predicts
that,
although
U.
S.
refinery
output
will
remain
relatively
unchanged,
net
imports
of
refined
petroleum
products
are
expected
to
increase
by
15
percent.
16
DOE
predicts
net
petroleum
imports
will
rise
to
at
least
10
million
bbl/
d
in
2010,
and
perhaps
as
high
as
15
million
bbl/
d
from
the
1990
level
of
7
million
bbl/
d
as
domestic
oil
production
is
expected
to
decline.
Imports
are
expected
to
supply
between
53
and
69
percent
of
U.
S.
petroleum
consumption
by
2010,
compared
with
42
percent
in
1990.
Refined
products
will
account
for
much
of
this
increase
because
most
of
the
expansion
in
the
world's
refinery
system
is
expected
to
take
place
outside
the
United
States.
17
Over
the
next
5
years,
the
petroleum
industry
as
a
whole
plans
to
increase
crude
oil
distillation
capacity
by
an
additional
2
percent,
or
272,000
bbl/
d,
of
which
44
percent
would
be
produced
by
new
facilities.
18
(
The
other
56
percent
includes
reactivations
and
expansions.)
The
level
of
added
demand
will
determine
if
this
added
capacity
is
sufficient
to
satisfy
the
market
without
driving
up
prices.

Companies
that
operate
refineries
with
greater
complexity
factors
(
often
the
largest
refineries)
will
presumably
be
in
a
more
favorable
position
to
make
the
necessary
capital
investments
for
the
transition
to
cleaner
fuels.
Such
refineries
will
most
likely
be
those
large
enough
to
benefit
from
the
economies
of
120
scale,
and
with
basic
downstream
configurations
to
facilitate
compliance
with
the
new
regulations.
A
financial
analysis
of
major
petroleum
refineries
in
the
1980s
conducted
by
DOE
concluded
that
vertically
integrated
firms
benefitted
in
a
period
characterized
by
increased
regulatory
activity
and
price
instability.
19
The
report
found
that
the
larger
companies
could
offset
a
loss
in
one
segment
with
gains
in
another.
(
It
is
important
to
note,
however,
that
in
the
long
run,
both
large
and
small
firms
would
close
refineries
which
operate
at
a
loss
over
time.)

In
contrast,
smaller,
independent,
and
less
complex
refineries
will
face
higher
marginal
compliance
costs,
and
may
not
find
it
economical
to
spend
the
required
environmental
capital.

Generally
not
as
flexible
as
the
larger,
integrated
companies,

these
firms
operate
at
greater
risk
from
the
effects
of
market
instability.
As
a
result,
an
industry
which
has
seen
a
high
level
of
consolidation
in
past
years
will
be
likely
to
see
more
concentration.
20
Overall,
the
effect
of
the
CAA
on
individual
refineries
is
dependent
upon
production
capacity,
economies
of
scale,
degree
of
self­
sufficiency,
capital
cost,
and
ability
of
refiners
to
"
pass
through"
higher
costs
to
consumers.
Predictions
of
the
effect
on
the
aggregate
industry
are
difficult
at
this
time
because
of
the
uncertainty
of
the
ability
of
some
refineries
to
develop
plans
for
compliance
pending
resolution
of
key
issues
affecting
their
operations.
A
recent
Harvard
University
study,
however,

predicted
that
the
promulgation
of
environmental
regulations
was
likely
to
result
in
the
early
phase
out
of
older,
less
sophisticated
facilities,
combined
with
the
upgrade
and
expansion
of
more
efficient,
complex
refineries
at
a
faster
rate.
21
6.1.5.2
Demand
Outlook.
DOC
projects
the
demand
for
all
petroleum
products
to
rise
slowly
and
steadily
over
the
next
5
years,
with
domestic
demand
for
refined
products
increasing
by
2.1
percent
in
1992,
assuming
an
economic
recovery
and
a
return
to
"
normal"
weather.
DOC's
longer
term
demand
prediction
is
for
a
steady
growth
rate
of
1
percent
through
1996.22,
23
Given
that
two­
thirds
of
petroleum
product
demand
is
attributable
to
the
121
transportation
sector,
projected
demand
growth
for
motor
gasoline
will
have
the
greatest
effect
on
refiners.
Industrial
demand
for
distillate
fuel
reflects
the
strongest
projected
growth.

According
to
DOE
projections,
the
consumption
of
diesel
fuel
in
the
transportation
sector
is
expected
to
grow
by
over
40
percent
between
1990
and
2010.24
Residential
and
commercial
sectors
are
expected
to
show
a
decrease
in
demand
for
petroleum
products.

DOE
has
also
projected
future
levels
of
demand.
Motor
gasoline
will
remain
the
leading
end
use
of
petroleum
products
throughout
DOE's
chosen
time
frame,
dropping
off
during
1990
and
1995,
and
rising
again
to
higher
levels
by
2010.
DOE
predicts
the
demand
for
residual
oil
to
rise,
level
off,
and
then
begin
to
decline
in
2010.
Jet
fuel
and
distillate
fuel
are
both
projected
to
rise
steadily
through
2010.

6.1.5.3
Price
Outlook.
Given
that
the
demand
for
motor
gasoline
is
price
inelastic,
the
added
capital
investment
that
refineries
will
be
required
to
undertake
in
the
production
of
reformulated
gasolines
is
likely
to
be
passed
on
to
consumers
in
the
form
of
a
price
increase.
DOC
has
estimated
this
price
increase
to
be
a
5
to
10
cent­
per­
gallon
rise
in
the
price
of
motor
gasoline.
25
In
a
recent
study
undertaken
by
the
National
Petroleum
Council,
the
impacts
of
air
quality
regulations
on
petroleum
refineries
were
assessed.
One
of
the
conclusions
of
the
study
was
that
the
costs
of
controlling
air
emissions
are
likely
to
be
passed
along
to
consumers
as
increases
in
the
final
price
of
refined
products.
(
The
study
offered
no
quantitative
projections,
however.)
26
DOE
has
projected
the
domestic
prices
of
petroleum
products
for
2010.
DOE
projects
the
average
price
for
all
petroleum
prices
to
increase
at
a
rate
in
the
range
of
0.4
percent
to
2.1
percent
annually.
These
price
increases
are
due
to
projected
increases
in
both
domestic
demand
and
crude
oil
prices.
DOE
also
accounted
for
higher
refining
and
distribution
expenses
in
making
these
projections.
The
real
price
of
motor
gasoline
is
projected
to
rise
from
$
1.17
per
gallon
in
1990
to
between
$
1.30
and
$
1.74
in
2010,
depending
on
the
level
of
world
crude
oil
prices.

Onhighway
diesel
fuel
is
projected
to
increase
to
between
$
1.27
and
122
$
1.69
per
gallon,
primarily
because
of
the
added
refinery
costs
of
desulfurization.
The
average
retail
price
of
residual
fuel
oil,
the
least
expensive
petroleum
product,
is
projected
to
be
within
the
range
of
$
25.52
to
$
40.79
per
barrel
in
2010.

If
refineries
are
able
to
accommodate
projected
increases
in
demand,
the
price
level
will
remain
fairly
stable.
However,

because
the
price
level
in
this
industry
is
contingent
upon
so
many
factors
independent
of
the
industry,
any
price
predictions
necessarily
have
their
limitations.
In
the
long
run,
therefore,

price
predictions
will
need
to
be
modified
with
the
occurrence
of
any
world
events
which
will
affect
the
supply
of
crude
oil
to
the
refineries
and
therefore
to
the
supply
of
refined
petroleum
products.
Refineries
will
also
be
faced
with
increasing
levels
of
emission
restrictions,
escalating
their
pollution
abatement
costs,
and
consequently,
the
price
of
their
products.

6.2
MARKET
MODEL
A
partial
equilibrium
model
is
the
analytical
tool
used
to
estimate
the
impact
of
the
final
NESHAP
on
the
petroleum
refining
industry.
Five
refined
petroleum
products
were
modeled.

Collectively,
these
products
represent
over
90
percent
of
the
refined
petroleum
products
sold
in
the
nation
annually.
These
products
include
motor
gasoline,
jet
fuel,
residual
fuel
oil,

distillate
fuel
oil,
and
liquified
petroleum
gases
(
LPGs).
It
is
assumed
that
firms
in
the
petroleum
refining
industry
operate
in
a
perfectly
competitive
market.
Although
the
petroleum
refinery
industry
does
not
meet
the
strictest
definition
of
a
perfectly
competitive
industry,
perfect
competition
seems
a
more
applicable
characterization
of
the
market
than
pure
monopoly.
The
assumption
of
perfect
competition
results
in
a
worst
case
scenario
of
model
results
from
the
perspective
of
the
impact
of
the
regulation
on
the
petroleum
refinery
industry.

6.2.1
Market
Supply
and
Demand
The
partial
equilibrium
model
approach
estimates
the
baseline
market
supply
and
demand
relationship
that
provides
the
framework
for
evaluating
market
changes
likely
to
occur
from
emission
controls.
The
baseline
or
pre­
control
petroleum
refining
market
123
Q
D


P

Q
S
d


P

Q
S
f


P

Q
D

Q
S
d

Q
S
f

Q
is
defined
by
a
domestic
market
demand
equation,
a
domestic
market
supply
equation,
and
a
foreign
market
supply
equation.
It
is
further
assumed
that
the
markets
will
clear
or
achieve
an
equilibrium.
The
following
equations
identify
the
market
demand,

supply,
and
equilibrium
conditions
for
the
petroleum
refinery
industry:

where:

Q
=
annual
output
or
quantity
of
petroleum
products
purchased
and
sold
in
the
United
States
QD
=
quantity
of
the
petroleum
products
domestically
demanded
annually
QSd
=
quantity
of
the
products
produced
by
domestic
suppliers
annually
QSf
=
quantity
of
the
products
produced
by
foreign
suppliers
annually
P
=
price
of
the
petroleum
product

=
price
elasticity
of
demand
for
the
product

=
price
elasticity
of
supply
for
the
product

,

,
and

are
parameters
estimated
by
the
model.

The
constants

,

,
and

are
computed
such
that
the
baseline
equilibrium
price
is
normalized
to
one.
The
market
specification
assumes
that
domestic
and
foreign
supply
elasticities
are
the
same.
This
assumption
was
necessary
because
data
were
not
readily
available
to
estimate
the
price
elasticity
of
supply
for
foreign
suppliers.
124
P

(
Q
S
d/

)
1

[
(
C

Q)

(
V

D)]
(
1

t)

D
S

k
6.2.2
Market
Supply
Shift
The
domestic
supply
equation
shown
above
may
be
solved
for
the
price
of
the
petroleum
product,
P,
to
derive
an
inverse
supply
function
that
will
serve
as
the
baseline
supply
function
for
the
industry.
The
inverse
domestic
supply
equation
for
the
industry
is
as
follows:

A
rational
profit
maximizing
business
firm
will
seek
to
increase
the
price
of
the
product
it
sells
by
an
amount
that
recovers
the
capital
and
operation
costs
of
the
regulatory
control
requirements
over
the
useful
life
of
the
emission
control
equipment.
This
relationship
is
identified
in
the
following
equation:

where:

C
=
increase
in
the
supply
price
Q
=
output
V
=
measure
of
annual
operating
and
maintenance
control
costs
t
=
marginal
corporate
income
tax
rate
S
=
capital
recovery
factor
D
=
annual
depreciation
(
assumes
straight
line
depreciation)

k
=
investment
cost
of
emission
controls
Thus,
the
model
assumes
that
individual
refineries
will
seek
to
increase
the
product
supply
price
by
an
amount
(
C)
that
equates
the
investment
costs
in
control
equipment
(
k)
to
the
present
value
of
the
net
revenue
stream
(
revenues
less
expenditures)

related
to
the
equipment.
Solving
the
equation
for
the
supply
price
increase
(
C)
yields
the
following
equation:
125
C

kS

D
Q(
1

t)

V

D
Q
D

k
T
S

r(
1

r)
T
[(
1

r)
T

1]
Estimates
of
the
annual
operation
and
maintenance
control
costs
and
of
the
investment
cost
of
emission
controls
(
V
and
k,

respectively)
were
obtained
from
engineering
studies
conducted
by
the
engineering
contractor
for
EPA
and
are
based
on
first
quarter
1992
price
levels.
The
variables
depreciation
and
capital
recovery
factor,
D
and
S,
respectively,
are
computed
as
follows:

where
r
is
the
discount
rate
faced
by
producers
and
is
assumed
to
be
a
rate
of
10
percent,
and
T
is
the
life
of
the
emission
control
equipment,
10
years
for
most
of
the
emission
control
equipment
proposed.

Emission
control
costs
will
increase
the
supply
price
for
each
refinery
by
an
amount
equivalent
to
the
per
unit
cost
of
the
annual
recovery
of
investment
costs
and
annual
operating
costs
of
emission
control
equipment,
or
C
i
(
i
denotes
domestic
refinery
1
through
192).
The
baseline
individual
refinery
cost
curves
are
unknown
because
production
costs
for
the
individual
refineries
are
unknown.
Therefore,
an
assumption
is
made
that
the
refineries
with
the
highest
after­
tax
per
unit
control
costs
are
marginal
in
the
post­
control
market,
or
that
those
firms
with
the
highest
after
tax
per
unit
control
costs
also
have
the
highest
per
unit
production
costs.
This
is
an
assumption
that
likely
causes
overestimates
of
impacts
and
may
not
be
the
case
in
reality.
Based
upon
this
assumption,
the
post­
control
supply
function
becomes
the
following:
126
P

(
Q
S
d/

)
1


C
(
C
i,
q
i)

where:

C
(
C
i,
q
i)
=
a
function
that
shifts
the
supply
function
to
reflect
control
costs
C
i
=
vertical
shift
that
occurs
in
the
supply
curve
for
the
ith
refinery
to
reflect
the
increased
cost
of
production
in
the
post­
control
market
q
i
=
quantity
produced
by
the
ith
refinery
This
industry
pre­
control
and
post­
control
supply
and
demand
is
illustrated
in
Figure
6­
1.
127
Figure
6­
1.
128
6.2.3
Impact
of
Supply
Shift
on
Market
Price
and
Quantity
The
impact
of
the
proposed
control
standards
on
market
equilibrium
price
and
output
are
derived
by
solving
for
the
postcontrol
market
equilibrium
and
comparing
the
new
equilibrium
price
and
quantity
(
P
1
and
Q
1,
respectively)
to
the
pre­
control
equilibrium
(
P
0
and
Q
0).
The
change
in
value
of
domestic
product
is
simply
the
difference
in
the
industry
revenue
(
P
1
*
Q
1)
at
the
post­
control
market
equilibrium
and
the
revenue
(
P
0
*
Q
0)
at
the
pre­
control
equilibrium.

Those
firms
that
lie
on
the
industry
supply
curve
at
price
and
quantity
levels
above
the
post­
control
equilibrium
(
P
1,
Q
1)
are
subject
to
closure.
This
assumption
is
consistent
with
the
assumption
of
perfect
competition.
Firms
in
a
competitive
market
are
price
takers
and
are
unable
to
sell
their
products
at
prices
above
the
market
equilibrium.

Predicted
primary
market
impacts
become
the
basis
for
assessing
economic
surplus
changes;
secondary
labor,
energy,
and
foreign
trade
market
impacts;
and
the
capital
availability
consequences
expected
to
result
from
the
emission
controls.

6.2.4
Trade
Impacts
Trade
impacts
are
reported
as
the
change
in
both
the
volume
and
dollar
value
of
net
exports
(
exports
minus
imports).
It
is
assumed
that
exports
comprise
an
equivalent
percentage
of
domestic
production
in
the
pre­
and
post­
control
markets.
The
supply
elasticities
in
the
domestic
and
foreign
markets
have
also
been
assumed
to
be
identical.
As
the
volume
of
imports
rises
and
the
volume
of
exports
falls,
the
volume
of
net
exports
will
decline.
However,
the
dollar
value
of
net
exports
may
rise
or
fall
when
demand
is
inelastic,
as
is
the
case
for
the
petroleum
products
of
interest.
The
dollar
value
of
imports
will
increase
since
both
the
price
and
quantity
of
imports
increase.

Alternatively,
the
quantity
of
exports
will
decline,
while
the
price
of
the
product
will
increase.
Price
increases
for
products
with
inelastic
demand
result
in
revenue
increases
for
the
producer.
Consequently,
the
dollar
value
of
exports
is
anticipated
to
increase.
Since
the
dollar
value
of
imports
and
exports
rise,
the
resulting
change
in
the
value
of
net
exports
129

Q
S
f

Q
S
f
1

Q
S
f
0

VIM

(
P
1

Q
S
f
1
)

(
P
0

Q
S
f
0
)


Q
S
d
x

Q
S
d
x
Q
S
d
0
(
Q
S
d
1

Q
S
d
0
)


VX

Q
S
d
x
Q
S
d
0
(
P
1
Q
S
d
1

P
0
Q
S
d
0
)
will
depend
on
the
magnitude
of
the
changes
for
imports
relative
to
exports.
The
following
functions
are
used
to
compute
the
trade
impacts:

where:


QSf
=
change
in
the
volume
of
imports

VIM
=
change
in
the
dollar
value
of
imports

Q
x
Sf
=
change
in
the
volume
of
exports

VX
=
change
in
the
dollar
value
of
exports
Q
x
Sd
=
quantity
of
exports
by
domestic
producers
in
the
pre­
control
market
The
subscripts
1
and
0
refer
to
the
post­
and
pre­
control
equilibrium
values,
respectively.
All
other
terms
have
been
previously
defined.

The
change
in
the
quantity
of
net
exports,

NX,
is
simply
the
difference
between
the
change
in
the
volume
of
exports
and
the
change
in
volume
of
imports,
or

Q
x
Sd
­

QSf.
The
reported
change
in
the
dollar
value
of
net
exports,

VNX,
is
the
difference
between
the
equations
for
change
in
value
of
exports
and
the
change
in
value
of
imports,
or

VX
­

VIM.
130
6.2.5
Changes
in
Economic
Welfare
Regulatory
control
requirements
will
result
in
changes
in
the
market
equilibrium
price
and
quantity
of
petroleum
products
produced
and
sold.
These
changes
in
the
market
equilibrium
price
and
quantity
will
affect
the
welfare
of
consumers
of
petroleum
products,
producers
of
petroleum
products,
and
society
as
a
whole.

Consumer
surplus
is
a
measure
of
the
well­
being
of
consumers
of
a
particular
product
and
it
represents
the
net
benefit
(
total
benefits
derived
from
consuming
a
good
less
the
expenditure
necessary
to
purchase
the
good)
associated
with
consuming
a
particular
product.
Consumers
of
refined
petroleum
products
will
bear
a
loss
in
consumer
surplus
as
a
result
of
proposed
emission
controls.
This
loss
in
consumer
surplus
(

CS)
represents
the
amount
consumers
would
have
been
willing
to
pay
over
the
precontrol
price
for
production
eliminated
and
a
loss
due
to
the
increase
in
the
market
price
consumers
must
pay
for
the
quantity
of
petroleum
products
purchased.

The
change
in
consumer
surplus
includes
losses
of
surplus
incurred
by
foreign
consumers
and
domestic
consumers.
Although
the
change
in
domestic
consumer
surplus
is
the
object
of
interest,
no
method
is
available
to
distinguish
the
marginal
consumer
as
domestic
or
foreign.
Therefore,
an
assumption
is
made
that
the
consumer
surplus
change
is
allocable
to
the
foreign
and
the
domestic
consumer
in
the
same
ratio
as
the
division
of
sales
between
foreign
and
domestic
consumers
in
the
pre­
control
market.

The
variable,

CS
d,
represents
the
change
in
domestic
consumer
surplus
that
results
from
the
change
in
market
equilibrium
price
and
quantity
resulting
from
the
imposition
of
regulatory
controls.
While

CS
is
the
change
in
consumer
surplus
from
the
perspective
of
the
world
economy,

CS
d
is
the
change
in
consumer
surplus
relevant
to
the
domestic
economy.

Producer
surplus
is
a
measure
of
well­
being
of
producers
in
an
industry.
The
change
in
producer
surplus
resulting
from
emission
controls
is
composed
of
two
elements.
The
first
element
relates
to
output
eliminated
as
a
result
of
controls.
The
second
element
131
is
associated
with
the
change
in
price
and
cost
of
production
for
the
new
market
equilibrium
quantity.
The
total
change
in
producer
surplus
is
the
sum
of
these
elements.
After­
tax
measures
of
surplus
changes
are
required
to
estimate
the
impacts
of
controls
on
producers'
welfare.
The
after­
tax
surplus
change
is
computed
by
multiplying
the
pre­
tax
surplus
change
by
a
factor
of
1
minus
the
tax
rate,
(
1­
t)
where
t
is
the
marginal
tax
rate.
Every
dollar
of
after­
tax
surplus
loss
represents
a
complimentary
loss
in
tax
revenues
of
t/(
1­
t)
dollars.

Output
eliminated
as
a
result
of
control
costs
cause
producers
to
suffer
a
welfare
loss
in
producer
surplus.
Refineries
remaining
in
operation
after
emission
controls
realize
a
welfare
gain
on
each
unit
of
production
for
the
incremental
increase
in
the
price
and
realize
a
decrease
in
welfare
per
unit
for
the
capital
and
operating
cost
of
emission
controls.
The
total
change
in
producer
surplus
(

PS)
is
the
sum
of
each
individual
change
in
producer
surplus.

Since
domestic
surplus
changes
are
the
object
of
interest,
the
welfare
gain
experienced
by
foreign
producers
due
to
higher
prices
is
not
considered.
This
procedure
treats
higher
prices
paid
for
imports
as
a
dead­
weight
loss
in
consumer
surplus.

Higher
prices
paid
to
foreign
producers
represent
simply
a
transfer
of
surplus
from
the
United
States
to
other
countries
from
a
world
economy
perspective,
but
a
welfare
loss
from
the
perspective
of
the
domestic
economy.

The
changes
in
economic
surplus
as
measured
by
the
change
in
consumer
and
producer
surplus
previously
discussed
must
be
adjusted
to
reflect
the
true
change
in
social
welfare
resulting
from
the
emission
controls.
Adjustments
must
be
made
to
consider
tax
effects
and
to
adjust
for
the
difference
between
the
social
discount
rate
and
the
private
discount
rate.
These
adjustments
result
in
a
number
referred
to
as
the
residual
surplus
to
society
since
these
surplus
changes
do
not
relate
specifically
to
consumers
or
producers
of
refined
petroleum
products,
but
rather
reflect
losses
that
must
be
borne
by
all
members
of
society.
132
EC


CS
d


PS


RS
Two
adjustments
are
necessary
to
adjust
changes
in
economic
surplus
for
tax
effects.
The
first
relates
to
the
per
unit
control
cost
(
Ci)
that
reflects
after­
tax
control
costs
and
is
used
to
predict
the
post­
control
market
equilibrium.
True
cost
of
emission
controls
must
be
measured
on
a
pre­
tax
basis.
A
second
tax­
related
adjustment
is
required
because
changes
reflect
the
after­
tax
welfare
impacts
of
emission
control
costs
on
affected
refineries.
As
noted
previously,
a
one
dollar
loss
in
pre­
tax
surplus
imposes
an
after­
tax
burden
on
the
affected
refinery
of
(
1­
t)
dollars.
Alternatively,
a
one
dollar
loss
in
after­
tax
producer
surplus
causes
a
complimentary
loss
of
t/(
1­
t)

dollars
in
tax
revenue.

Economic
surplus
must
also
be
adjusted
because
the
private
and
social
discount
rates
differ.
The
private
discount
rate
is
used
to
shift
the
supply
curve
of
firms
in
the
industry
since
this
rate
reflects
the
marginal
cost
of
capital
to
affected
firms.

The
shift
in
the
supply
curve
for
the
refining
industry
is
used
to
estimate
primary
and
secondary
market
impacts.
A
private
cost
of
capital
of
10
percent
is
assumed
for
the
analysis.

In
contrast,
the
economic
costs
of
regulation
must
consider
the
social
cost
of
capital
rather
than
the
private
cost
of
capital.
A
social
cost
of
capital
of
7
percent
is
assumed
for
the
analysis.
This
rate
reflects
the
social
opportunity
cost
of
resources
displaced
in
the
economy
by
investments
required
for
emission
controls.
The
adjustment
for
the
two
tax
effects
and
the
social
cost
of
capital
are
referred
to
as
the
residual
change
in
economic
surplus
to
society
(

RS).

The
total
economic
costs
of
the
proposed
regulations
are
the
sum
of
the
changes
in
consumer
surplus,
producer
surplus,
and
the
residual
surplus
to
society.
This
relationship
is
defined
by
the
following
equation:

where
EC
is
the
economic
cost
of
the
proposed
controls
and
all
other
variables
have
been
previously
defined.
133
6.2.6
Labor
Market
and
Energy
Market
Impacts
Emission
control
costs
will
result
in
a
decrease
in
the
market
equilibrium
quantity
of
refined
products
produced
and
sold
domestically.
This
reduction
in
output
or
production
will
directly
cause
the
level
of
inputs
used
in
production
to
decrease.
Quantification
of
the
input
reduction
affecting
the
labor
and
energy
markets
are
of
particular
interest.

Two
adjustments
in
the
labor
market
may
result
from
the
emission
controls.
The
first
involves
monitoring
and
maintenance
of
the
emission
control
equipment
that
may
cause
employment
increases.
Information
necessary
to
quantify
potential
employment
increases
for
monitoring
and
maintenance
of
emission
controls
is
not
readily
available.
Consequently,
possible
employment
increases
are
not
considered
in
the
analysis.

Additionally,
job
losses
may
occur
as
a
result
of
decreases
in
the
level
of
production
for
firms
in
the
industry.
Probable
job
losses
due
to
the
estimated
decrease
in
refined
petroleum
output
are
quantified
by
multiplying
the
decrease
in
industry
output
by
an
industry
ratio
of
employees
per
unit
of
production.
This
quantification
of
possible
job
losses
in
the
refining
industry
is
likely
to
be
overstated
due
to
the
omission
of
potential
job
increases
for
monitoring
and
maintenance
of
emission
control
equipment.

Reduction
in
the
utilization
of
energy
inputs
associated
with
the
final
standard
result
from
decreases
in
output
in
the
industry.
The
expected
change
in
expenditures
on
energy
by
firms
in
the
industry
is
calculated
by
multiplying
the
ratio
of
baseline
energy
expenditure
per
dollar
refined
petroleum
output
by
the
estimated
decrease
in
annual
output.
The
quantification
of
energy
input
changes
reflects
energy
expenditure
decreases
per
year
occurring
as
a
result
of
the
reduced
production
of
refined
petroleum
products.

6.2.7
Baseline
Inputs
The
partial
equilibrium
model
requires,
as
data
inputs,

baseline
values
for
variables
and
parameters
that
characterize
the
petroleum
refining
market.
These
data
inputs
include
the
number
of
domestic
refineries
in
operation
in
1992,
the
annual
134
production
per
refinery
for
1992,
and
the
relevant
control
costs
per
refinery.
All
monetary
values
are
based
upon
1992
price
levels.
Specific
details
concerning
the
data
inputs
and
the
sources
of
the
data
are
available
in
the
Economic
Impact
Analysis
of
the
Petroleum
Refinery
NESHAP
(
1995).

Two
data
inputs
crucial
to
the
estimation
of
partial
equilibrium
are
the
price
elasticity
of
demand
and
the
price
elasticity
of
supply.
The
price
elasticities
of
supply
and
demand
are
briefly
discussed
in
the
following
section.

6.2.8
Price
Elasticities
of
Demand
and
Supply
Price
elasticities
of
demand
and
supply
are
measures
of
the
responsiveness
of
buyers
and
sellers
of
a
product
to
changes
in
the
market
price.
Elasticity
measures
may
be
categorized
as
elastic,
unitary
elastic,
and
inelastic
to
price
changes
in
the
market.
Products
with
elastic
price
elasticity
values
are
very
responsive
to
changes
in
the
price
of
the
product
(
percent
quantity
decrease
exceeds
percent
price
increase)
while
products
with
inelastic
price
elasticity
measures
are
not
very
responsive
to
changes
in
price
(
percent
quantity
decrease
is
less
than
percent
price
increase).
Unitary
elasticity
measures
have
equal
percent
changes
in
price
and
quantity.
The
ultimate
increase
in
market
equilibrium
price
and
decrease
in
market
equilibrium
quantity
resulting
from
emission
controls
are
dependent
upon
the
magnitude
of
the
per
unit
control
costs
and
elasticity
measures
in
the
market.
The
relative
burden
of
emission
control
costs
between
consumers
and
producers
will
be
determined
by
the
comparative
magnitudes
of
the
supply
and
demand
elasticities
prevailing
in
a
market,
all
other
factors
being
equal.
The
more
inelastic
demand
is
for
a
product,
the
larger
the
share
of
emission
control
costs
that
will
be
paid
by
consumers
of
the
product
in
the
form
of
higher
product
prices.
Alternatively,
the
more
inelastic
the
supply
curve,
the
larger
the
share
of
emission
control
costs
that
will
be
paid
by
suppliers.

6.2.8.1
Price
Elasticity
of
Demand.
The
price
elasticity
of
demand
represents
the
percentage
change
in
the
quantity
demanded
resulting
from
each
1
percent
change
in
the
price
of
the
product.

Petroleum
products
represent
a
very
important
energy
source
for
135
the
United
States.
Many
studies
have
been
conducted
which
estimate
the
price
elasticity
of
demand
for
some
or
all
of
the
petroleum
products
of
interest
and
numerous
published
sources
of
the
price
elasticity
of
demand
for
petroleum
products
exist.

These
elasticity
measures
are
used
in
the
analysis
and
are
listed
in
Table
6­
1.
Sources
of
these
data
are
discussed
in
detail
in
the
Industry
Profile
for
the
Petroleum
Refinery
NESHAP
(
1993).

TABLE
6­
1.
ESTIMATES
OF
PRICE
ELASTICITY
OF
DEMAND
FUEL
TYPE
ELASTICITY
RANGE
MID­
POINT
ELASTICITY
Motor
Gasoline
Jet
fuel
Residual
Fuel
Oil
Distillate
Fuel
Oil
Liquified
Petroleum
Gas
­
0.55
to
­
0.8227
­
0.1528
­
0.61
to
­
0.7427
­
0.50
to
­
0.9927
­
0.60
to
­
1.027
­
0.69
­
0.15
­
0.675
­
0.745
­
0.80
The
elasticity
estimates
for
each
of
the
products
reflect
that
each
of
these
products
have
inelastic
demand.
The
only
exception
is
the
upper
end
of
the
range
of
elasticities
for
LPGs
that
is
unitary
elastic.
As
previously
stated,
regulatory
control
costs
are
more
likely
to
paid
by
consumers
of
products
with
inelastic
demand
when
compared
to
elastic
demand,
all
other
things
held
constant.
Price
increases
for
products
with
inelastic
demand
lead
to
revenue
increases
for
producers
of
the
product.
Thus,

one
can
predict
that
price
increases
resulting
from
implementation
of
regulatory
control
costs
will
lead
to
higher
revenues
for
the
petroleum
refining
industry,
all
other
factors
held
constant.
The
market
changes
resulting
from
the
regulations
are
based
upon
the
midpoint
of
the
range
of
demand
elasticities.

A
sensitivity
analysis
of
this
assumption
was
made
using
the
upper
and
lower
bounds
of
the
range
of
elasticities.
136
6.2.8.2
Price
Elasticity
of
Supply.
The
price
elasticity
of
supply
or
own­
price
elasticity
of
supply
is
a
measure
of
the
responsiveness
of
producers
to
changes
in
the
price
of
a
product.

The
price
elasticity
of
supply
indicates
the
percentage
change
in
the
quantity
supplied
of
a
product
resulting
from
each
1
percent
change
in
the
price
of
the
product.

Published
sources
of
the
price
elasticity
of
supply
using
current
data
were
not
readily
available.
It
was
determined
that
the
price
elasticity
of
supply
should
be
estimated
econometrically
using
time
series
data.
Several
estimation
approaches
were
considered
and
are
discussed
in
detail
in
the
Economic
Impact
Analysis
of
the
Petroleum
Refinery
NESHAP
(
1994).

The
approach
actually
used
to
estimate
the
price
elasticity
of
supply
was
a
time
series
model
of
the
production
function
for
the
petroleum
refining
industry.
Relevant
factors
of
production
in
the
model
included
labor,
capital,
and
materials
(
crude
oil).

The
econometric
results
of
the
production
function
estimation
and
efficient
market
assumptions
were
used
to
derive
a
price
elasticity
of
supply
for
the
petroleum
products
of
interest
of
1.24.
This
estimate
of
the
price
elasticity
of
supply
for
the
five
petroleum
products
reflects
that
the
petroleum
refinery
industry
in
the
U.
S.
will
increase
production
of
gasoline,
jet
fuel,
residual
fuel
oil,
distillate
fuel
oil
and
LPGS
jointly
by
1.24
percent
for
every
1.0
percent
increase
in
the
price
of
these
products.
Elasticity
measures
for
the
individual
products
were
not
calculated
due
to
statistical
modeling
problems.
Limitations
of
the
elasticity
measure
estimate
are
discussed
in
detail
in
the
Economic
Impact
Analysis
and
in
a
limited
manner
in
6.4
Limitations
of
the
Economic
Model.

6.3
CAPITAL
AVAILABILITY
ANALYSIS
It
is
necessary
to
estimate
the
impact
of
the
proposed
emission
controls
on
the
financial
performance
of
affected
petroleum
refineries
and
on
the
ability
of
the
refineries
to
finance
the
additional
capital
investment
in
emission
control
equipment.
Financial
data
were
not
available
for
the
majority
of
the
refineries
in
the
industry.
Available
data
were
obtained
137
roi


1990
i

1986
n
i
a
i
/
5

100
only
for
the
largest
publicly
held
petroleum
refining
companies.

For
this
reason,
the
capital
availability
analysis
has
been
conducted
on
an
industrywide
basis.

One
measure
of
financial
performance
frequently
used
to
assess
profitability
of
a
firm
is
net
income
before
interest
expense
as
a
percentage
of
firm
assets
or
rate
of
return
on
investment.
The
pre­
control
rate
of
return
on
investment
(
roi)
is
calculated
as
follows:

where
n
i
is
income
before
interest
payments
and
a
i
is
total
assets.
A
five­
year
average
is
used
to
avoid
annual
fluctuations
that
may
occur
in
income
data.
The
proposed
regulations
potentially
could
have
an
effect
on
income
before
taxes
(
n)
i
for
firms
in
the
industry
and
on
the
level
of
assets
for
firms
in
the
industry
(
a
i.)
Since
firm
specific
data
were
unavailable
for
all
of
the
affected
firms,
sample
financial
data
collected
by
the
American
Petroleum
Institute
(
API)
were
used.
29
Data
from
the
API
study
are
available
in
Industry
Profile
for
the
Petroleum
Refinery
NESHAP.
The
sample
studied
by
API
represents
71
percent
of
net
income
in
the
industry
and
70
percent
of
total
industry
assets.
These
percentages
are
considered
to
estimate
changes
in
the
financial
ratios
and
are
necessary
to
allocate
changes
in
income
and
assets
resulting
from
emission
controls
to
the
study
sample.
There
is
a
great
diversity
among
the
refineries
in
the
industry;
therefore,
individual
firm
financial
performance
may
vary
greatly
from
the
sample
estimate.
The
post­
control
return
on
investment
(
proi)
is
calculated
as
follows:
138
proi


1990
i

1986
n
i
/
5


n

1990
i

1986
a
i
/
5

k

100
where:

proi
=
the
post­
control
return
on
investment

n
=
the
change
in
income
before
interest
resulting
from
implementation
of
emission
controls
for
firms
in
the
sample

k
=
capital
expenditures
associated
with
emission
controls.

The
equation
proi
will
tend
to
overstate
the
impact
of
the
control
measure
on
the
rate
of
return
on
investment
for
the
industry
over
the
life
of
the
emission
controls.
This
is
true
because
net
capital
investment
in
emission
controls
will
decline
as
capital
is
depreciated.

The
ability
of
affected
firms
to
finance
the
capital
equipment
associated
with
the
emission
control
is
also
relevant
to
the
analysis.
Numerous
financial
ratios
can
be
examined
to
analyze
the
ability
of
a
firm
to
finance
capital
expenditures.
One
such
measure
is
historical
profitability
measures
such
as
rate
of
return
on
investment.
The
analysis
approach
for
this
measure
has
been
previously
described.
The
bond
rating
of
a
firm
is
another
indication
of
the
credit
worthiness
of
a
firm
or
the
ability
of
a
firm
to
finance
capital
expenditures
with
debt
capital.
Such
data
are
unavailable
for
many
of
the
firms
subject
to
the
regulation,
and
consequently
bond
ratings
are
not
analyzed.

Ability
to
pay
interest
payments
is
another
criterion
sometimes
used
to
assess
the
capability
of
a
firm
to
finance
capital
expenditures.
Coverage
ratios
provide
such
information.
The
interest
coverage
ratio,
or
the
number
of
times
income
(
before
taxes
and
interest)
will
pay
interest
expense,
is
a
ratio
that
provides
some
information
about
the
ability
of
a
firm
to
cover
or
139
tc


1990
i

1986
ebit
i
interest
i
/
5
ptc


1990
i

1986
ebit
i
/
5


ebit

1990
i

1986
interest
i
/
5


interest
pay
annual
interest
obligations.
The
pre­
control
measure
of
coverage
ratio
is
as
follows:

where:

tc
=
number
of
times
earnings
will
pay
annual
interest
charges
ebit
=
earnings
before
interest
payments
and
taxes
interest
i
=
annual
interest
expense
Post­
control
coverage
ratios
may
be
estimated
as
follows:

where:


ebit
=
estimated
change
in
earnings
before
interest
and
taxes
of
the
firm

interest
i
=
anticipated
change
in
interest
expense
All
other
variables
have
been
previously
described.
The

interest
is
calculated
by
multiplying
the
capital
expenditures
for
the
proposed
controls
(

k)
by
the
assumed
private
cost
of
capital
(
10
percent).
This
is
generally
lower
than
the
overall
cost
of
capital
for
a
firm.
Again
the
interest
coverage
ratios
of
individual
petroleum
refineries
may
differ
from
the
average
significantly.

Finally,
the
degree
of
debt
leverage
or
debt­
equity
ratio
of
a
firm
is
considered
in
assessing
the
ability
of
a
firm
to
finance
capital
expenditures.
The
pre­
control
debt­
equity
ratio
is
the
following:
140
d/
e

d
1990
d
1990

e
1990
pd/
e

d
1990

k
d
1990

e
1990

k
where:

d/
e
=
debt
equity
ratio
d
=
debt
capital
e
=
equity
capital
Since
capital
information
is
less
volatile
than
earnings
information,
it
is
appropriate
to
use
the
latest
available
information
for
this
calculation.
If
one
assumes
that
the
capital
costs
of
control
equipment
are
financed
solely
by
debt,

the
debt­
equity
ratio
becomes:

where
pd/
e
is
the
post­
control
debt­
equity
ratio
assuming
that
the
control
equipment
costs
are
financed
solely
with
debt.

Obviously,
firms
may
choose
to
issue
capital
stock
to
finance
the
capital
expenditure
or
to
finance
the
investment
through
internally
generated
funds.
The
assumption
that
the
capital
costs
are
financed
solely
by
debt
may
be
viewed
as
a
conservative
scenario.

The
methods
used
to
analyze
the
capital
availability
do
have
some
limitations.
The
approach
matches
1990
debt
and
equity
values
with
estimated
capital
expenditures
for
control
equipment.

Average
1986
through
1990
income
and
asset
measures
are
matched
with
changes
in
income
and
capital
expenditures
associated
with
the
control
measures.
The
control
cost
changes
and
income
changes
reflect
1992
price
levels.
The
financial
data
used
in
the
analysis
represents
the
most
recent
data
available.
It
is
inappropriate
to
simply
index
the
income,
asset,
debt,
and
equity
values
to
1992
price
levels
for
the
following
reasons.
Assets,

debt,
and
equity
represent
embedded
values
that
are
not
subject
141
to
price
level
changes
except
for
new
additions
such
as
capital
expenditures.
Income
is
volatile
and
varies
from
period
to
period.
For
this
reason,
average
income
measures
are
used
in
the
study.
The
analysis
reflects
a
conservative
approach
to
analyzing
the
changes
likely
in
financial
ratios
for
the
petroleum
industry.
Some
decreases
the
cost
of
production
expected
to
result
from
implementation
of
emission
controls
have
not
been
considered.
These
include
labor
input
and
energy
input
cost
decreases.
Annualized
compliance
costs
are
overstated
from
a
financial
income
perspective
since
these
costs
include
a
component
for
earnings
or
return
on
investment.
In
general,
the
approach
followed
is
a
scenario
that
overstates
the
negative
impact
of
the
emission
controls
on
the
financial
operations
of
the
petroleum
refining
industry.

6.4
LIMITATIONS
OF
THE
ECONOMIC
MODEL
Several
qualifications
of
the
model
presented
must
be
made.

First,
the
partial
equilibrium
model
estimated
for
each
of
the
five
petroleum
products
assumes
that
a
single
homogeneous
product
is
sold
in
a
national
market.
In
the
actual
market,
there
may
be
some
differentiation
of
the
refined
petroleum
products
sold
throughout
the
country
and
regional
barriers
to
trade
may
exist
in
the
petroleum
refinery
market.
Product
differentiation
and
regional
barriers
to
trade
would
allow
firms
in
the
industry
to
have
greater
market
power.
Market
power
enables
firms
to
have
more
control
over
the
market
price
of
the
product
sold
and
would
lessen
the
impact
of
emission
controls
costs
on
firms
in
the
industry.

Next,
an
assumption
is
made
in
the
model
that
refineries
with
the
highest
per
unit
control
cost
are
marginal
in
the
postcontrol
market.
Firms
with
the
highest
per
unit
control
costs
are
assumed
to
have
the
highest
underlying
cost
of
production.

This
assumption
was
necessary
due
to
lack
of
available
information
concerning
the
cost
of
production
on
an
individual
refinery
basis.

Additionally,
a
review
of
the
data
indicates
refineries
that
are
marginal
in
the
post­
control
market
have
per
unit
control
142
costs
that
significantly
exceed
the
average.
This
may
be
the
result
of
the
engineering
method
used
to
assign
costs
to
individual
refineries.
Moreover,
the
cost
allocation
methodology
assigns
all
of
the
control
costs
to
the
five
petroleum
products
of
interest.
These
products
represent
less
than
one
hundred
percent
of
the
refined
petroleum
products
produced
domestically.

Finally,
some
plants
may
find
that
the
price
increase
resulting
from
the
regulations
make
it
profitable
to
expand
production.
This
would
occur
if
a
firm
found
its
post­
control
incremental
cost
to
be
less
that
the
post­
control
market
price.

Expansion
by
these
firms
would
result
in
a
smaller
decrease
in
output
and
increase
in
price
than
otherwise
would
occur.
The
foregoing
list
of
qualifications
tend
to
overstate
the
impacts
of
the
proposed
emission
controls
on
the
market
equilibrium
price
and
quantity,
revenues,
and
plant
closures.

Estimates
of
model
results
are
dependent
on
the
price
elasticity
measures
assumed
for
demand
and
supply.
A
sensitivity
analysis
of
the
price
elasticity
of
demand
reflects
minimal
changes
in
the
market
results
with
alternative
lower
and
upper
bound
elasticity
measures.
(
See
the
Economic
Impact
Analysis
for
the
Petroleum
Refinery
NESHAP
for
details.)

The
methodology
used
to
estimate
the
price
elasticity
of
supply
also
must
be
qualified.
The
elasticity
measure
does
not
estimate
the
supply
elasticities
for
the
individual
products
or
directly
consider
the
interrelationships
between
products.
The
assumption
implicit
in
use
of
this
supply
elasticity
estimate
is
that
the
elasticities
of
the
individual
petroleum
products
will
not
differ
significantly
from
the
elasticity
of
the
products
combined.
This
does
not
seem
a
totally
unreasonable
assumption
since
the
same
factor
inputs
are
used
to
produce
each
of
the
petroleum
products.
The
methodology
also
does
not
explicitly
consider
the
cross­
price
elasticities
for
the
petroleum
products.

Since
these
products
are
joint
products,
changes
in
the
price
of
one
product
will
have
an
effect
on
the
quantity
supplied
of
the
other
products.

The
uncertainty
of
the
supply
estimate
is
acknowledged.
It
is
possible
to
conduct
a
sensitivity
analysis
of
the
price
143
elasticity
supply.
Such
an
analysis
would
quantify
the
impact
of
this
assumption
on
the
reported
market
results.
Given
the
magnitude
of
market
impact
results,
reasonable
variations
in
the
price
elasticity
of
supply
are
unlikely
to
alter
the
model
results
significantly.

The
estimates
of
the
secondary
impacts
associated
with
the
emission
controls
are
based
on
changes
predicted
by
the
partial
equilibrium
model.
The
limitations
previously
described
are
applicable
to
primary
and
secondary
economic
impacts.
As
previously
noted,
the
estimated
employment
losses
do
not
consider
potential
employment
gains
for
operating
the
emission
control
equipment.
It
is
important
to
note
that
the
potential
job
losses
predicted
by
the
model
are
only
those
directly
linked
to
predicted
production
losses
in
the
petroleum
refining
industry.

Likewise,
the
gains
or
losses
in
markets
indirectly
affected
by
the
regulations,
such
as
substitute
product
markets,
complement
products
markets,
or
in
markets
that
use
petroleum
products
as
inputs
have
not
been
considered
in
this
analysis.

The
capital
availability
analysis
also
has
limitations.
Some
of
these
limitations
have
been
previously
noted.
Future
baseline
performance
may
not
resemble
past
levels.
Future
financial
performance
of
the
petroleum
refining
industry
will
be
affected
by
market
considerations
other
than
emission
control
measures,

and
these
factors
are
not
readily
estimated.
Additionally,
the
tools
used
in
the
analysis
are
limited
in
scope
and
do
not
fully
describe
the
financial
position
of
individual
firms
within
the
industry
but
are
more
reflective
of
industry
averages.
Finally,

the
approach
used
to
estimate
the
impact
of
the
control
costs
on
the
financial
ratios
tends
to
overstate
the
effect
of
emission
control
costs
on
these
ratios.

6.5
PRIMARY
IMPACT,
CAPITAL
AVAILABILITY
ANALYSIS,
AND
SECONDARY
IMPACT
RESULTS
Estimates
of
the
primary
economic
impacts,
secondary
impacts,

and
capital
availability
consequences
associated
with
the
chosen
option
or
preferred
alternative
are
presented.
As
previously
discussed,
Alternative
1
requires
MACT
floor
controls
on
all
144
emission
points
other
than
equipment
leaks
where
Option
1
controls
are
less
costly.
Primary
impacts
related
to
control
cost
associated
with
Alternative
1
include
changes
in
the
market
equilibrium
price
and
output
levels,
changes
in
the
value
of
shipments
or
revenues
to
domestic
producers,
and
plant
closures.

Secondary
impacts
relate
to
labor
market,
energy
market
and
international
trade
effects
likely
to
occur
as
a
result
of
the
emission
control
requirements.
The
capital
availability
analysis
assesses
the
ability
of
affected
firms
to
raise
capital,
and
the
impacts
of
control
costs
on
plant
profitability.

6.5.1
Estimates
of
Primary
Impacts
The
partial
equilibrium
model
is
used
to
analyze
the
market
outcome
of
the
proposed
regulation.
The
purchase
of
emission
control
equipment
will
result
in
an
upward
vertical
shift
in
the
domestic
supply
curve
for
refined
petroleum
products.
The
height
of
the
shift
is
determined
by
the
after­
tax
cash
flow
required
to
offset
the
per
unit
increase
in
production
costs.
Since
the
control
costs
vary
for
each
of
the
domestic
refineries,
the
postcontrol
supply
curve
is
segmented,
or
a
step
function.

Underlying
production
costs
for
each
refinery
are
unknown;

therefore,
a
worst
case
scenario
has
been
assumed.
The
plants
with
the
highest
control
costs
per
unit
of
production
are
assumed
to
also
have
the
highest
pre­
control
per
unit
cost
of
production.

Thus,
firms
with
the
highest
per
unit
cost
of
emission
control
are
assumed
to
be
marginal
in
the
post­
control
market.

Foreign
supply
is
assumed
to
have
the
same
price
elasticity
of
supply
as
domestic
supply.
The
United
States
had
a
negative
trade
balance
for
each
of
the
refined
products
in
1992
with
the
exception
of
distillate
fuel
oil
that
had
a
slightly
positive
trade
balance
of
$
1.1
million.
Therefore
net
exports
are
negative
for
all
products
except
distillate
fuel
oil
in
the
baseline
model.
Foreign
and
domestic
post­
control
supply
are
added
together
to
form
the
total
post­
control
market
supply.
The
intersection
of
this
post­
control
supply
with
market
demand
will
determine
the
new
market
equilibrium
price
and
quantity.

Postcontrol
domestic
output
is
derived
by
deducting
post­
control
imports
from
the
post­
control
output.
145
Table
6­
2
reveals
the
primary
impacts
predicted
by
the
partial
equilibrium
model
for
Alternative
1.
The
range
of
anticipated
price
increases
for
the
five
products
vary
from
$
0.03
to
$
0.14
per
barrel
produced
for
residual
fuel
oil
and
jet
fuel,

respectively.
The
percentage
increases
for
each
product
are
less
than
1
percent
and
range
from
0.26
percent
to
0.53
percent.

Production
is
expected
to
decrease
by
12.5
million
barrels
per
year
for
all
products,
an
overall
decrease
in
domestic
production
of
0.24
percent.
The
estimated
annual
reductions
in
production
of
the
individual
products
range
from
0.65
million
barrels
to
5.67
million
barrels
for
jet
fuel
and
motor
gas,
respectively.

The
production
percentage
decreases
range
from
0.13
percent
to
0.58
percent
for
jet
fuel
and
residual
fuel
oil,
respectively.

Value
of
domestic
shipments
or
revenues
for
domestic
producers
are
expected
to
increase
for
the
five
products
approximately
$
107
million
annually.
The
predicted
changes
in
revenues
for
individual
products
range
from
an
increase
of
$
56
million
in
motor
gasoline
revenues
to
a
decrease
in
residual
fuel
revenues
of
approximately
$
12
million
annually.
The
percent
changes
range
from
an
increase
of
0.41
percent
in
jet
fuel
to
a
decrease
of
0.26
percent
in
residual
fuel
oil
revenues.
Economic
theory
predicts
that
revenue
increases
are
expected
to
occur
when
prices
are
increased
for
inelastic
goods,
all
other
factors
held
constant.
This
phenomenon
results
from
the
percentage
increase
in
price
exceeding
the
percentage
decrease
in
quantity
for
goods
with
inelastic
demand.
All
of
the
refined
petroleum
products
follow
the
expected
trend
except
residual
fuel
oil.
146
TABLE
6­
2.
SUMMARY
OF
PRIMARY
IMPACTS
Estimated
Impacts
Refined
Product
Price
Increases1
Production
Decreases2
Value
of
Domestic
Shipments3
Motor
gasoline
Amount
Percentage
Jet
fuel
Amount
Percentage
Residual
fuel
Amount
Percentage
Distillate
fuel
Amount
Percentage
LPGs
Amount
Percentage
TOTAL
$
0.09
0.29%

$
0.14
0.53%

$
0.03
0.24%

$
0.08
0.29%

$
0.07
0.26%
(
5.67)
(
0.22%)

(
0.65)
(
0.13%)

(
1.62)
(
0.50%)

(
2.78)
(
0.26%)

(
1.80)
(
0.25%)

(
12.52)
$
55.63
0.07%

$
53.22
0.41%

($
11.92)
(
0.26%)

$
8.06
0.03%

$
2.42
0.01%

$
107.41
NOTES:
(
)
indicate
decreases.
1Prices
are
shown
in
price
per
barrel
($
1992).
2Annual
production
quantities
are
shown
in
millions
of
barrels.
3Values
of
domestic
shipments
are
shown
in
millions
of
1992
dollars.
147
Residual
fuel
oil
has
the
highest
trade
deficit
of
the
five
products
with
over
40
percent
of
domestic
demand
being
imported.

The
magnitude
of
residual
fuel
oil
imports
causes
a
decrease
in
domestic
residual
fuel
oil
revenues
to
occur
in
the
post­
control
market.

It
is
anticipated
that
between
0
and
7
refineries
are
at
risk
of
closure
as
a
result
of
the
decrease
in
production
predicted
by
the
model,
with
the
actual
number
likely
being
closer
to
0
than
7.
Those
refineries
with
the
highest
per
unit
control
costs
are
assumed
to
be
marginal
in
the
post­
control
market.
Refineries
that
have
post­
control
supply
prices
that
exceed
the
market
equilibrium
price
are
assumed
to
close.
This
assumption
is
consistent
with
the
perfect
competition
theory
that
presumes
all
firms
in
the
industry
are
price
takers.
Firms
with
the
highest
per
unit
control
costs
may
not
have
the
highest
underlying
cost
of
production.
This
is
an
assumption
that
likely
overstates
the
the
likely
number
of
plant
closures
and
other
adverse
effects
of
the
emission
controls.

The
estimated
primary
impacts
reported
depend
on
the
set
of
parameters
used
in
the
partial
equilibrium
model.
One
of
the
parameters,
the
price
elasticity
of
demand,
consisted
of
a
range
for
four
of
the
five
refined
products.
The
midpoint
of
the
range
of
elasticities
was
used
to
estimate
the
reported
primary
and
secondary
impacts.
A
sensitivity
analysis
of
this
assumption
was
conducted.
The
low
and
high
end
of
the
range
of
elasticities
are
inputs
in
the
sensitivity
analysis.
In
general,
the
sensitivity
analysis
shows
that
the
estimated
primary
impacts
are
relatively
insensitive
to
reasonable
changes
of
price
elasticity
of
demand
estimates.
Estimates
of
market
impacts
with
lower
elasticity
measures
shift
relatively
more
of
the
burden
of
the
emission
controls
to
consumers
in
the
form
of
slightly
higher
price
increases
and
lower
output
decreases.
Higher
elasticity
measures
shift
more
of
the
burden
to
producers
in
the
form
of
slightly
lower
price
increases
and
higher
output
decreases.

6.5.2
Capital
Availability
Analysis
148
The
capital
availability
analysis
involves
examining
pre­
and
post­
control
values
of
selected
financial
ratios.
These
ratios
include
rate
of
return
on
investment,
times
interest
earned
coverage
ratio,
and
the
debt­
equity
ratio.
Data
were
not
available
to
estimate
the
ratios
for
many
refineries
in
the
industry.
Consequently,
these
ratios
have
been
analyzed
on
an
industrywide
basis.
Since
the
industrywide
ratios
represent
an
average
for
the
industry,
individual
firms
within
the
industry
may
have
financial
ratios
that
differ
significantly
from
the
average.
Net
income
was
averaged
for
a
five
year
period
(
1986
through
1990)
to
avoid
annual
fluctuations
in
income
that
may
occur
due
to
changes
in
the
business
cycle.
Debt
and
equity
capital
are
not
subject
to
annual
fluctuations;
therefore,
the
most
recent
data
available
(
1990)
were
used
in
the
analysis.

The
financial
statistics
provide
insight
regarding
firms'

ability
to
raise
capital
to
finance
the
investment
in
emission
control
equipment.
Table
6­
3
shows
the
estimated
impact
on
financial
ratios
for
the
industry.

TABLE
6­
3.
ANALYSIS
OF
FINANCIAL
RATIOS
Financial
Ratios
Pre­
Control
Ratios
Post­
Control
Ratios
Rate
of
return
on
investment
5.91%
5.91%

Coverage
Ratio
(
or
Times
Interest
Earned)
7.08
7.07
Debt­
Equity
Ratio
62.75%
62.76%

The
financial
ratios
remain
virtually
unchanged
as
a
result
of
the
proposed
emission
controls.
The
magnitude
of
the
income
changes
and
the
capital
expenditures
necessary
for
the
emission
control
measures
do
not
significantly
alter
the
financial
position
of
the
industry.
The
impact
of
the
standards
on
149
individual
refineries,
however,
may
vary
greatly
from
the
industry
averages
used
in
this
analysis.

6.5.3
Labor
Market
Impacts
and
Energy
Market
Impacts
The
estimated
labor
impacts
associated
with
the
NESHAP
are
based
on
the
results
of
the
partial
equilibrium
analyses
of
the
five
refined
petroleum
products
and
are
reported
in
Table
6­
4.

The
number
of
workers
employed
by
firms
in
SIC
2911
is
estimated
to
decrease
by
approximately
114
workers
as
a
result
of
the
proposed
emission
controls.
The
loss
in
number
of
workers
depends
primarily
on
the
estimated
reduction
in
production.
Gains
in
employment
anticipated
to
result
from
operation
and
maintenance
of
control
equipment
and
from
additional
monitoring,

recordkeeping,
and
reporting
requirements
have
not
been
included
in
the
analysis
are
not
considered
in
the
labor
impact
estimate.

Estimates
of
employment
losses
do
not
consider
potential
employment
gains
in
industries
that
produce
substitute
products.

Similarly,
losses
in
employment
in
industries
that
use
petroleum
products
as
an
input
or
in
industries
that
provide
complement
goods
are
not
considered.
The
changes
in
employment
reflected
in
this
analysis
are
only
direct
employment
losses
due
to
reductions
in
domestic
production
of
refined
petroleum
products.

The
loss
in
employment
of
114
jobs
annually
is
small
relative
to
the
total
employment
in
the
industry.
The
magnitude
of
predicted
job
losses
is
a
direct
results
of
from
the
relatively
small
decrease
in
production
estimated
by
the
model,
and
by
the
relatively
low
labor
intensity
in
the
industry.
It
is
quite
possible
if
the
gains
from
employment
could
have
been
considered
in
the
analysis,
then
the
predicted
loss
in
employment
would
be
less.

The
method
used
to
estimate
reductions
in
use
of
energy
inputs
relates
the
energy
expenditures
to
the
level
of
production.
An
estimated
decrease
in
energy
input
use
of
nearly
$
11
million
annually
is
expected
for
the
industry.
The
individual
product
energy
use
changes
are
reported
in
Table
6­
4.
As
production
decreases,
the
amount
of
energy
input
utilized
by
the
refining
industry
also
declines.
The
changes
in
energy
use
do
not
reflect
the
increased
energy
use
associated
with
operating
and
150
maintaining
emission
control
equipment.
Insufficient
data
were
available
to
consider
such
changes
in
energy
costs.
151
TABLE
6­
4.
SUMMARY
OF
SECONDARY
REGULATORY
IMPACTS
Estimated
Impacts
Refined
Product
Labor
Input1
Energy
Input2
Motor
gasoline
Amount
Percentage
Jet
fuel
Amount
Percentage
Residual
fuel
Amount
Percentage
Distillate
fuel
Amount
Percentage
LPGs
Amount
Percentage
Total
five
products
Amount
(
52)
(
0.22%)

(
6)
(
0.13%)

(
15)
(
0.50%)

(
25)
(
0.26%)

(
16)
(
0.25%)

(
114)
($
5.79)
(
0.22%)

($
0.52)
(
0.13%)

($
0.71)
(
0.50%)

($
2.27)
(
0.26%)

($
1.56)
(
0.25%)

($
10.85)

NOTES:
(
)
Indicates
decreases.
1Indicates
estimated
reduction
in
number
of
jobs.
2Reduction
in
energy
use
in
millions
of
1992
dollars.
152
6.5.4
Foreign
Trade
Impacts
The
implementation
of
the
NESHAP
will
increase
the
cost
of
production
for
domestic
refineries
relative
to
foreign
refineries,
all
other
factors
being
equal.
This
change
in
the
relative
price
of
imports
will
cause
domestic
imports
of
refined
petroleum
products
to
increase
and
domestic
exports
to
decrease.

The
balance
of
trade
overall
for
refined
petroleum
products
is
currently
negative
(
imports
exceed
exports).
The
NESHAP
will
likely
cause
the
trade
deficit
to
increase.
Net
exports
are
likely
to
decline
by
2.3
million
barrels
per
year.
The
range
of
net
export
decreases
vary
from
0.21
million
barrels
to
0.91
million
barrels
for
LPGs
and
residual
fuel
oil,
respectively.

The
related
percent
decreases
range
from
0.54
percent
to
40.9
percent
for
LPGs
and
distillate
fuel
oil,
respectively.
The
large
percentage
decrease
in
exports
of
distillate
is
the
result
of
the
product
having
a
very
small
positive
trade
balance
in
the
pre­
control
market.
The
dollar
value
of
the
total
decline
in
net
exports
is
expected
to
amount
to
$
68.2
million
annually.
The
predicted
changes
in
the
trade
balance
are
reported
in
Table
6­
5.

6.5.5
Regional
Impacts
No
significant
regional
impacts
are
expected
from
implementation
of
the
NESHAP.
Between
0
and
7
refineries
are
estimated
to
close
nationwide,
with
the
point
estimate
likely
closer
to
0
than
7.
Due
to
the
manner
used
to
estimate
control
costs
for
the
individual
refinery
and
the
method
of
allocating
the
costs
to
products,
the
facilities
predicted
to
close
do
not
necessarily
represent
the
facilities
most
likely
to
close.

However,
the
facilities
postulated
in
the
model
are
dispersed
throughout
the
United
States
and
are
not
specific
to
a
particular
geographical
region.
Employment
impacts
are
directly
related
to
plant
closure
and
production
decreases.
Employment
impacts
are
also
dispersed
throughout
the
country.

6.6
SUMMARY
The
estimated
market
changes
resulting
from
the
proposed
emission
controls
are
relatively
small.
Predicted
price
increases
and
reductions
in
domestic
output
are
less
than
1
percent
for
each
of
the
refined
products.
The
value
of
domestic
153
shipments
or
revenues
to
domestic
producers
are
anticipated
to
increase
for
the
5
product
categories
by
a
total
of
$
107
million
annually
($
1992).
Emission
controls
costs
are
small
relative
to
the
financial
resources
of
affected
producers,
and
on
average,

refineries
should
not
find
it
difficult
to
raise
the
capital
necessary
to
finance
the
purchase
and
installation
of
emission
controls.
Between
0
and
7
refineries
may
close
as
a
result
of
the
emission
controls,
with
the
point
estimate
of
the
range
likely
being
closer
to
0
than
7.

The
estimated
secondary
economic
impacts
are
also
relatively
small.
Approximately
114
job
losses
may
occur
nationwide,
given
the
effect
on
labor
that
are
considered
in
the
analysis.
Energy
input
reductions
are
estimated
to
be
approximately
$
11
million
annually.
A
decrease
is
net
exports
of
2.3
million
barrels
annually
in
refined
products
is
anticipated
to
occur.
No
regional
impacts
are
expected.

TABLE
6­
5.
FOREIGN
TRADE
(
NET
EXPORTS)
IMPACTS
Estimated
Impacts
Refined
Product
Amount1
Percentage
Dollar
Value
of
Net
Export
Change2
Motor
Gasoline
Jet
fuel
Residual
fuel
Distillate
fuel
LPGs
Total
(
0.43)

(
0.23)

(
0.91)

(
0.48)

(
0.21)

(
2.26)
(
0.54%)

(
1.41%)

(
0.81%)

(
40.92%)

(
0.54%)
($
21.92)

($
8.14)

($
16.81)

($
12.67)

($
8.68)

($
68.22)

NOTES:
(
)
indicates
decreases.
1Millions
of
barrels.
2Millions
of
dollars
($
1992).
154
6.7
POTENTIAL
SMALL
BUSINESS
IMPACTS
6.7.1
Introduction
The
Regulatory
Flexibility
Act
(
RFA)
of
1980
and
EPA
Guidelines
for
Regulatory
Flexibility
Analyses
(
1992)
require
that
special
consideration
be
given
to
the
effects
of
all
proposed
regulations
on
small
business
entities.
The
Act
requires
that
a
determination
be
made
as
to
whether
the
subject
regulation
will
have
a
significant
impact
on
a
substantial
number
of
small
entities;
the
Guidelines
require
that
a
final
Regulatory
Flexibility
Analysis
be
done
if
any
impact
on
small
entities
occurs.
The
analysis
used
four
criteria
provided
in
the
original
Federal
Guidelines
for
Regulatory
Flexibility
Analyses
(
1982).
A
substantial
number
is
considered
to
be
greater
than
20
percent
of
the
small
entities
identified.
The
following
criteria
are
provided
for
assessing
whether
impacts
are
significant.
The
impact
on
small
business
entities
is
considered
significant
whenever
any
of
the
following
criteria
are
met:

1.
annual
compliance
costs
(
annualized
capital,
operating,

reporting,
etc.)
increase
as
a
percentage
of
cost
of
production
for
small
entities
for
the
relevant
process
or
product
by
more
than
5
percent;

2.
compliance
costs
as
a
percent
of
sales
for
small
entities
are
at
least
10
percent
higher
than
compliance
costs
as
a
percent
of
sales
for
large
entities;

3.
capital
costs
of
compliance
represent
a
significant
portion
of
capital
available
to
small
entities,

considering
internal
cash
flow
plus
external
financing
capabilities;
and
4.
the
requirements
of
the
regulation
are
likely
to
result
in
closure
of
small
entities.

6.7.2
Methodology
155
Data
are
not
readily
available
to
estimate
the
small
business
impacts
for
two
of
the
criteria
(
1
and
3)
listed
in
the
previous
section.
The
information
necessary
to
make
such
comparisons
are
generally
considered
proprietary
by
small
business
firms.

Consequently,
the
analysis
will
focus
on
remaining
two
(
2
and
4)

criteria
of
the
potential
for
adverse
impacts.
Closure
of
small
businesses
and
a
comparison
of
the
compliance
costs
as
a
percentage
of
sales
for
small
and
large
business
entities
will
be
examined.

The
closure
method
of
analysis
will
focus
on
the
number
of
petroleum
refineries
expected
to
close
as
a
result
of
the
emission
controls
and
the
relative
size
of
the
firms
at
risk.

Alternatively,
a
measure
of
annual
compliance
costs
as
a
percentage
of
sales
will
also
be
considered.
The
ratio
of
costs
to
sales
will
be
compared
for
small
refineries
to
the
same
ratio
for
all
other
refineries.

6.7.3
Categorization
of
Small
Businesses
Consistent
with
Title
IV,
Section
410
of
the
CAA,
a
petroleum
refinery
is
classified
as
a
small
business
if
it
has
less
than
1,500
employees
or
has
annual
production
less
than
50,000
barrels
produced
per
day.
A
refinery
must
also
be
unaffiliated
with
another
large
business
entity.
Information
necessary
to
distinguish
refinery
size
by
number
of
employees
was
not
readily
available.
However,
daily
production
data
were
available
from
the
Oil
and
Gas
Journal,
U.
S.
Refinery
Survey
(
1­
1­
92).
Based
upon
the
production
size
criterion,
there
were
63
operating
refineries
in
1992
that
could
be
categorized
as
small
business
entities.

6.7.4
Small
Business
Impacts
The
results
of
the
partial
equilibrium
analysis
lead
to
the
conclusion
that
between
0
and
7
refineries
are
at
risk
of
closure,
with
the
actual
number
likely
closer
to
0
than
7.
The
upper
end
of
the
estimate
represents
approximately
four
percent
of
the
domestic
refineries
in
operation
and
11
percent
of
those
designated
to
be
small
businesses.
The
estimated
number
of
closures
is
therefore
less
than
20
percent
of
the
small
refineries.
However,
it
is
important
to
note
that
the
firms
156
designated
in
the
model
as
being
at
the
greatest
risk
for
closure
were
small
refineries.

Compliance
costs
as
a
percentage
of
sales
were
computed
both
for
the
small
refineries
and
for
those
refineries
that
are
not
considered
small.
The
cost
to
sales
ratio
for
the
small
refineries
was
0.19
percent
of
sales
while
the
cost
to
sales
ratio
for
all
other
refineries
was
0.08
percent.
The
differential
between
these
two
rates
exceeds
ten
percent,
and
consequently,
a
conclusion
is
drawn
that
a
significant
number
of
small
businesses
are
adversely
affected
by
the
promulgated
regulations.

6.8
SOCIAL
COSTS
OF
REGULATION
The
social
costs
of
regulation
are
those
costs
borne
by
society
for
pollution
abatement.
From
an
economic
perspective,

the
social
costs
of
regulation
represent
the
opportunity
costs
of
scarce
resources
utilized
for
pollution
control,
or
the
economic
costs.
Scarce
resources
used
in
pollution
control
could
alternatively
be
used
by
society
for
purposes
other
than
emission
control.
Thus,
a
social
loss
or
economic
cost
occurs.

Consumers,
producers,
and
all
of
society
bear
the
costs
of
pollution
controls.
Economic
losses
to
consumers
result
from
the
higher
prices
paid
for
goods
consumed
and
the
lesser
quantity
goods
consumed.
Producers
benefit
from
a
higher
price
paid
by
consumers
for
each
unit
of
product
sold
but
incur
compliance
costs
for
each
unit
of
production.
Producers
also
sell
a
smaller
quantity
of
the
good
after
controls
are
implemented.
Finally,
it
is
necessary
to
adjust
the
preceding
changes
in
consumer
and
producer
surplus
to
reflect
the
regulation's
cost
to
society.

The
change
in
residual
surplus
represent
tax
revenues
that
may
be
gained
or
lost
from
the
emission
controls
and
the
differential
in
the
private
cost
of
capital
and
the
social
cost
of
capital.
The
economic
costs
of
regulation
(
EC)
as
previously
defined
consists
of
the
sum
of
the
change
in
domestic
consumer
surplus
(

CS
d),

the
change
in
producer
surplus
(

PS),
and
the
change
in
the
residual
surplus
to
society
(

RS)
resulting
from
the
emission
controls.
157
6.8.1
Social
Cost
Estimates
The
components
of
the
social
costs
of
regulation
have
been
previously
discussed.
More
details
on
the
exact
methodology
for
calculating
for
these
values
are
contained
in
the
Economic
Impact
for
the
Petroleum
Refinery
NESHAP
(
1994).
The
economic
costs
of
Alternative
1
(
the
set
of
chosen
alternatives)
are
displayed
in
Table
6­
6.
The
social
costs
of
Alternative
1
are
estimated
from
the
partial
equilibrium
model
and
are
divided
into
changes
in
consumer,
producer,
and
residual
surplus.

TABLE
6­
6.
ANNUAL
SOCIAL
COST
ESTIMATES
FOR
THE
PETROLEUM
REFINING
REGULATION
(
Millions
of
1992
dollars)

Social
Cost
Category
Net
Costs1
Surplus
Costs
for
Preferred
Option:
Change
in
Consumer
Surplus
Change
in
Producer
Surplus
Change
in
Residual
Surplus
to
Society2
$
399.2
$(
242.1)
$(
101.7)

Total
Social
Cost
of
Alternative
13
$
94.0
NOTES:
1Brackets
indicate
negative
surplus
losses,
or
surplus
gains.
2Residual
surplus
loss
to
society
includes
adjustments
necessary
to
equate
the
relevant
discount
rate
to
the
social
cost
of
capital
and
to
consider
appropriate
tax
effect
adjustments.
3Alternative
1
includes
floor
controls
for
all
emission
points
except
equipment
leaks.
Option
1
is
preferred
to
the
floor
for
equipment
leaks
because
it
is
a
less
costly
option
than
the
floor.
158
REFERENCES
1.
Robert
Beck
and
Joan
Biggs.
OGJ
300.
Oil
&
Gas
Journal.
Vol.
89.
No.
39.
Tulsa,
OK.
September
1991.

2.
U.
S.
Department
of
Commerce.
Petroleum
Refining
C
U.
S.
Industrial
Outlook
1992.
Washington,
DC.
January
1992.

3.
American
Petroleum
Institute.
Market
Shares
and
Individual
Company
Data
for
U.
S.
Energy
Markets,
1950­
1989.
Discussion
Paper
#
014R.
Washington,
DC.
October
1990.

4.
U.
S.
Department
of
Energy.
The
U.
S.
Petroleum
Refining
Industry
in
the
1980'
s.
DOE/
EIA­
0536.
Energy
Information
Administration.
October
1990.

5.
U.
S.
Department
of
Energy.
Annual
Outlook
for
Oil
and
Gas.
DOE/
EIA­
0517(
91).
Energy
Information
Administration.
Washington,
DC.
June
1991.

6.
U.
S.
Department
of
Energy.
Performance
Profiles
of
Major
Energy
Producers,
1990.
DOE/
EIA­
0206(
90).
Energy
Information
Administration.
Washington,
DC.
December
1991.

7.
Cambridge
Energy
Research
Associates.
The
U.
S.
Refining
Industry:
Facing
the
Challenges
of
the
1990s.
Prepared
for
U.
S.
Department
of
Energy.
January
1992.

8.
Robert
S.
Pindyck
and
Daniel
L.
Rubinfeld.
Microeconomics.
MacMillan
Publishing
Co.
1989.

9.
U.
S.
Department
of
Energy.
The
U.
S.
Petroleum
Industry:
Past
as
Prologue
1970­
1992.
DOE/
EIA­
0572.
Energy
Information
Administration,
Office
of
Oil
and
Gas.
Washington,
DC.
September
1993.

10.
Bonner
&
Moore
Management
Science.
Overview
of
Refining
and
Fuel
Oil
Production.
Houston,
TX.
April
29,
1982.

11.
U.
S.
Department
of
Energy.
Annual
Report
to
Congress.
DOE/
EIA­
0173(
91).
Energy
Information
Administration.
Washington,
DC.
March
1992.

12.
Dermot
Gately.
New
York
University.
Taking
Off:
The
U.
S.
Demand
for
Air
Travel
and
Jet
Fuel.
The
Energy
Journal.
Vol.
9.
No.
4.
1988.

13.
U.
S.
Department
of
Energy.
Petroleum
Marketing
Annual,
1990.
DOE/
EIA­
0487(
90).
Energy
Information
Administration.
Washington,
DC.
December
1991.

14.
Reference
2.
159
15.
U.
S.
Department
of
Commerce.
Petroleum
Refining
C
U.
S.
Industrial
Outlook
1991.
Washington,
DC.
January
1991.

16.
Reference
2.

17.
U.
S.
Department
of
Energy.
Annual
Energy
Outlook,
1992.
DOE/
EIA­
0383(
92).
Energy
Information
Administration.
Washington,
DC.
January
1992.

18.
Reference
15.

19.
Reference
4.

20.
Reference
2.

21.
Henry
Lee
and
Ranjit
Lamech.
The
Impact
of
Clean
Air
Act
Amendments
on
U.
S.
Energy
Security.
Harvard
University.
Energy
93­
01.
Cambridge,
MA.
1993.

22.
Reference
2.

23.
Reference
15.

24.
Reference
17.

25.
Reference
15.

26.
National
Petroleum
Council.
Estimated
Expenditures
by
Petroleum
Refineries
to
Meet
New
Regulatory
Initiatives
Air
Quality.
For
presentation
at
the
86th
Annual
Air
&
Waste
Management
Association
Meeting.
Denver,
CO.
93­
WA­
78A.
03.
June
13­
18,
1993.

27.
U.
S.
Department
of
Energy,
Short­
term
Energy
Outlook,
Vol.
II.
DOE/
EIA­
0202/
42.
Energy
Information
Administration.
Washington,
DC.
August
1980.

28.
Robert
S.
Pindyck
and
Daniel
L.
Rubinfeld.
Microeconomics.
MacMillan
Publishing
Company.
1989.

29.
American
Petroleum
Institute.
Financial
Trends
for
Leading
U.
S.
Oil
Companies
1968­
1990.
Discussion
Paper
#
017R.
Washington,
DC.
October,
1991.
160
161
7.0
QUALITATIVE
ASSESSMENT
OF
BENEFITS
OF
EMISSION
REDUCTIONS
One
rationale
for
environmental
regulation
is
to
provide
benefits
to
society
by
improving
environmental
quality.
In
this
chapter,
and
the
two
chapters
which
follow,
information
is
provided
on
the
types
and
levels
of
social
benefits
anticipated
from
the
petroleum
refinery
NESHAP.
This
chapter
examines
the
potential
health
and
welfare
benefits
associated
with
air
emission
reductions
projected
as
a
result
of
implementation
of
the
petroleum
refinery
NESHAP.
The
final
regulation
is
expected
to
reduce
emissions
of
HAPs
emitted
from
storage
tanks,
process
vents,
equipment
leaks,
and
wastewater
emission
points
at
refining
sites.
Of
the
HAPs
emitted
by
petroleum
refineries,

some
are
classified
as
VOCs,
which
are
ozone
precursors.

In
general,
the
reduction
of
HAP
emissions
resulting
from
promulgation
and
implementation
of
the
petroleum
refinery
NESHAP
will
reduce
human
and
environmental
exposure
to
these
pollutants
and
thus,
reduce
potential
adverse
health
and
welfare
effects.

This
chapter
provides
a
general
discussion
of
the
various
components
of
total
benefits
that
may
be
gained
from
a
reduction
in
HAPs
through
the
subject
NESHAP.
HAP
benefits
are
presented
separately
from
the
benefits
associated
specifically
with
VOC
emission
reductions.

7.1
IDENTIFICATION
OF
POTENTIAL
BENEFIT
CATEGORIES
The
benefit
categories
associated
with
the
emission
reductions
predicted
for
this
regulation
can
be
broadly
categorized
as
those
162
benefits
which
are
attributable
to
reduced
exposure
to
HAPs,
and
those
attributable
to
reduced
exposure
to
VOCs.
The
predicted
emissions
of
a
few
HAPs
associated
with
this
regulation
have
been
classified
as
probable
or
known
human
carcinogens.
As
a
result,

one
of
the
benefits
of
the
proposed
regulation
is
a
reduction
in
the
risk
of
cancer
mortality.
Other
benefit
categories
include:

reduced
exposure
to
noncarcinogenic
HAPs,
and
reduced
exposure
to
VOCs.
In
addition
to
health
impacts
occurring
as
a
result
of
reductions
in
HAP
and
VOC
emissions,
there
are
welfare
impacts
which
can
also
be
identified.
In
general,
welfare
impacts
include
effects
on
crops
and
other
plant
life,
materials
damage,

soiling,
and
visibility.
Each
category
is
discussed
separately
in
the
following
section.

7.2
QUALITATIVE
DESCRIPTION
OF
AIR
RELATED
BENEFITS
A
summary
of
the
range
of
potential
physical
health
and
welfare
effects
categories
that
may
be
associated
with
HAP
emissions
and
also
with
concentrations
of
ozone
formed
by
VOC
HAPs
is
provided
in
Table
7­
1.
As
noted
in
the
table,
exposure
to
HAPs
can
lead
to
a
variety
of
acute
and
chronic
health
impacts
as
well
as
welfare
impacts.
The
health
and
welfare
benefits
of
HAP
and
VOC
reductions
are
presented
separately.

7.2.1
Benefits
of
Decreasing
HAP
Emissions
Human
exposure
to
HAPs
may
occur
directly
through
inhalation
or
indirectly
through
ingestion
of
food
or
water
contaminated
by
HAPs
or
through
dermal
exposure.
HAPs
may
also
enter
terrestrial
and
aquatic
ecosystems
through
atmospheric
deposition.
HAPs
can
be
deposited
on
vegetation
and
soil
through
wet
or
dry
deposition.
HAPs
may
also
enter
the
aquatic
environment
from
the
atmosphere
via
gas
exchange
between
surface
water
and
the
ambient
air,
wet
or
dry
deposition
of
particulate
HAPs
and
particles
to
which
HAPs
adsorb,
and
wet
or
dry
deposition
to
watersheds
with
subsequent
leaching
or
runoff
to
bodies
of
water.
1
This
analysis
is
focused
only
on
the
air
quality
benefits
of
HAP
reduction.
163
7.2.1.1
Health
Benefits
of
Reduction
in
HAP
Emissions.

According
to
baseline
emission
estimates,
this
source
category
currently
emits
approximately
81,000
Mg
of
HAPs
annually.
The
petroleum
refinery
NESHAP
will
regulate
several
of
the
189
air
toxics
listed
in
Section
112(
b)
of
the
CAA.
Exposure
to
ambient
concentrations
of
these
pollutants
may
result
in
a
variety
of
adverse
health
effects
considering
both
cancer
and
noncancer
endpoints.
164
TABLE
7­
1.
POTENTIAL
HEALTH
AND
WELFARE
EFFECTS
ASSOCIATED
WITH
EXPOSURE
TO
HAZARDOUS
AIR
POLLUTANTS2
Effect
Type
Effect
Category
Effect
End­
Point
Citation
Health
Mortality
Carcinogenicity
Genotoxicity
Non­
Cancer
lethality
EPA
(
1990)
3,
Graham
et
al.

(
1989)
4
Graham
et
al.
(
1989)
5
Voorhees
et
al.
(
1989)
6
Chronic
Morbidity
Neurotoxicity
Immunotoxicity
Pulmonary
function
decrement
Liver
damage
Gastrointestinal
toxicity
Kidney
damage
Cardiovascular
impairment
Hematopoietic
(
Blood
disorders)
Reproductive/
Developmental
toxicity
All
morbidity
end­
points
obtained
from
Graham
et
al.
(
1989)
7
Voorhees
et
al.

(
1989)
8,
Cote
et
al.

(
1988)
9
Acute
Morbidity
Pulmonary
function
decrement
Dermal
irritation
Eye
irritation
Welfare
Materials
Damage
Corrosion/
Deterioration
NAS
(
1975)
10
165
Aesthetic
Unpleasant
odors
Transportation
safety
concerns
Agriculture
Yield
reductions/
Foliar
injury
Stern
et
al.
(
1973)
11
Ecosystem
Structure
Biomass
decrease
Species
richness
decline
Species
diversity
decline
Community
size
decrease
Organism
lifespan
decrease
Trophic
web
shortening
Weinstein
and
Birk
(
1989)
12
166
Many
HAPs
are
classified
as
known
human
carcinogens.
Speciation
of
the
HAP
emissions
at
refining
sites
was
available
only
for
equipment
leaks.
Of
those
HAPs
(
presented
in
Table
3­
2),
only
benzene
is
classified
as
known
human
carcinogens,
according
to
an
EPA
system
for
classifying
chemicals
by
cancer
risk.
This
means
that
there
is
sufficient
evidence
to
support
that
exposure
to
this
chemical
causes
an
increased
risk
of
cancer
in
humans.

Benzene
is
a
concern
to
EPA
because
long
term
exposure
to
this
chemical
has
been
known
to
cause
leukemia
in
humans.
While
this
is
the
most
well
known
effect,
benzene
exposure
is
also
associated
with
aplastic
anemia,
multiple
myeloma,
lymphonomas,

pancytopenia,
chromosomal
breakages,
and
weakening
of
bone
marrow.
13
Therefore,
a
reduction
in
human
exposure
to
benzene
could
lead
to
a
decrease
in
cancer
risk
and
ultimately
to
a
decrease
in
cancer
mortality.

Cresols
are
considered
to
be
group
C
or
possible
human
carcinogens.
For
these
HAPs,
there
are
limited
data
on
animal
carcinogenicity,
but
no
data
on
human
carcinogenicity.
Data
are
currently
inadequate
to
quantitatively
estimate
possible
cancer
risks
associated
with
cresol
exposure.

The
remaining
HAPs
emitted
by
equipment
leaks
at
refining
sites
have
not
been
shown
to
cause
cancer.
However,
exposure
to
these
pollutants
may
still
result
in
adverse
health
impacts
to
human
and
non­
human
populations.
Noncancer
health
effects
can
be
grouped
into
the
following
broad
categories:
genotoxicity,

developmental
toxicity,
reproductive
toxicity,
systemic
toxicity,

and
irritation.
Genotoxicity
is
a
broad
term
that
usually
refers
to
a
chemical
that
has
the
ability
to
damage
DNA
or
the
chromosomes.
Developmental
toxicity
refers
to
adverse
effects
on
a
developing
organism
that
may
result
from
exposure
prior
to
conception,
during
prenatal
development,
or
postnatally
to
the
time
of
sexual
maturation.
Adverse
developmental
effects
may
be
detected
at
any
point
in
the
life
span
of
the
organism.

Reproductive
toxicity
refers
to
the
harmful
effects
of
HAP
exposure
on
fertility,
gestation,
or
offspring,
caused
by
exposure
of
either
parent
to
a
substance.
Systemic
toxicity
affects
a
portion
of
the
body
other
than
the
site
of
entry.
167
Irritation,
for
the
purpose
of
this
document,
refers
to
any
effect
which
results
in
irritation
of
the
eyes,
skin,
and
respiratory
tract.
14
There
are
particular
noncancer
effects
in
humans
associated
with
exposure
to
several
of
these
HAPs.
Brief
exposure
to
HCl
can
cause
ulceration
of
the
respiratory
tract;
brief
exposure
to
phenol
can
cause
mortality;
and
brief
exposure
to
HF
can
cause
severe
respiratory
damage.
n­
hexane
can
cause
polyneuropathy
(
muscle
weakness,
numbness),
and
naphthalene's
noncancer
effects
include
cataracts
and
anemia
in
humans.

For
the
HAPs
covered
by
the
petroleum
refinery
NESHAP,

evidence
on
the
potential
toxicity
of
the
pollutants
varies.

Given
sufficient
exposure
conditions,
each
of
these
HAPs
has
the
potential
to
elicit
adverse
health
or
environmental
effects
in
the
exposed
populations.
It
can
be
expected
that
emission
reductions
achieved
through
the
subject
NESHAP
will
decrease
the
incidence
of
these
adverse
health
effects.

7.2.1.2
Welfare
Benefits
of
Reduction
in
HAP
Emissions.
The
welfare
effects
of
exposure
to
HAPs
have
received
less
attention
from
analysts
than
the
health
effects.
However,
this
situation
is
changing,
especially
with
respect
to
the
effects
of
toxic
substances
on
ecosystems.
Over
the
past
ten
years,

ecotoxicologists
have
started
to
build
models
of
ecological
systems
which
focus
on
interrelationships
in
function,
the
dynamics
of
stress,
and
the
adaptive
potential
for
recovery.

This
perspective
is
reflected
in
Table
7­
1
where
the
end­
points
associated
with
ecosystem
functions
describe
structural
attributes
rather
than
species
specific
responses
to
HAP
exposure.
This
is
consistent
with
the
observation
that
chronic
sub­
lethal
exposures
may
affect
the
normal
functioning
of
individual
species
in
ways
that
make
it
less
than
competitive
and
therefore
more
susceptible
to
a
variety
of
factors
including
disease,
insect
attack,
and
decreases
in
habitat
quality.
15
All
of
these
factors
may
contribute
to
an
overall
change
in
the
structure
(
i.
e.,
composition)
and
function
of
the
ecosystem.
168
The
adverse,
non­
human
biological
effects
of
HAP
emissions
include
ecosystem
and
recreational
and
commercial
fishery
impacts.
Atmospheric
deposition
of
HAPs
directly
to
land
may
affect
terrestrial
ecosystems.
Atmospheric
deposition
of
HAPs
also
contributes
to
adverse
aquatic
ecosystem
effects.
This
not
only
has
adverse
implications
for
individual
wildlife
species
and
ecosystems
as
a
whole,
but
also
the
humans
who
may
ingest
contaminated
fish
and
waterfowl.
In
general,
HAP
emission
reductions
achieved
through
the
petroleum
refinery
NESHAP
should
reduce
the
associated
adverse
environmental
impacts.

7.2.2
Benefits
of
Reduced
VOC
Emissions
Emissions
of
VOCs
have
been
associated
with
a
variety
of
health
and
welfare
impacts.
VOC
emissions,
together
with
NO
x,

are
precursors
to
the
formation
of
tropospheric
ozone.
It
is
exposure
to
ambient
ozone
that
is
most
directly
responsible
for
a
series
of
respiratory
related
adverse
impacts.
Consequently,

reductions
in
the
emissions
of
VOCs
will
also
lead
to
reductions
in
the
types
of
health
and
welfare
impacts
that
are
associated
with
elevated
concentrations
of
ozone.
In
this
section,
the
benefits
of
reducing
VOC
emissions
are
examined
in
terms
of
reductions
in
ozone.

7.2.2.1
Health
Benefits
of
Reduction
in
VOC
Emissions.
Human
exposure
to
elevated
concentrations
of
ozone
primarily
results
in
respiratory­
related
impacts
such
as
coughing
and
difficulty
in
breathing.
Eye
irritation
is
another
frequently
observed
effect.

These
acute
effects
are
generally
short­
term
and
reversible.

Nevertheless,
a
reduction
in
the
severity
or
scope
of
such
impacts
may
have
significant
economic
value.

Recent
studies
have
found
that
repeated
exposure
to
elevated
concentrations
of
ozone
over
long
periods
of
time
may
also
lead
to
chronic,
structural
damage
to
the
lungs.
16
To
the
extent
that
these
findings
are
verified,
the
potential
scope
of
benefits
169
related
to
reductions
in
ozone
concentrations
could
be
expanded
significantly.

Major
ozone
health
effects
are:
alterations
in
lung
capacity
and
breathing
frequency;
eye,
nose
and
throat
irritation;
reduced
exercise
performance;
malaise
and
nausea;
increased
sensitivity
of
airways;
aggravation
of
existing
respiratory
disease;

decreased
sensitivity
to
respiratory
infection;
and
extrapulmonary
effects
(
central
nervous
system,
liver,

cardiovascular,
and
reproductive
effects).
17
In
general,
it
is
expected
that
reductions
in
VOCs
through
the
petroleum
refinery
NESHAP
regulation
is
a
mechanism
by
which
the
ambient
ozone
concentration
may
be
reduced
and,
in
turn,
reduce
the
incidence
of
the
adverse
health
effects
of
ozone
exposure.
In
this
section,
the
benefits
of
reducing
VOC
emissions
is
examined
in
terms
of
reductions
in
ozone.

7.2.2.2
Welfare
Benefits
of
VOC
Reduction.
In
addition
to
acute
and
(
possible)
chronic
health
impacts
of
ozone
exposure,

there
are
adverse
welfare
effects.
The
principal
welfare
impact
is
related
to
losses
in
economic
value
for
certain
agricultural
crops
and
ornamental
plants.
Over
the
last
decade,
a
series
of
field
experiments
has
demonstrated
a
positive
statistical
association
between
ozone
exposure
and
reductions
in
yield
as
well
as
visible
injury
to
several
economically
valuable
cash
crops,
including
soybeans
and
cotton.
Damage
to
selected
timber
species
has
also
been
associated
with
exposure
to
ozone.
The
observed
impacts
range
from
foliar
injury
to
reduced
growth
rates
and
premature
death.
Benefits
of
reduced
ozone
concentrations
include
both
the
value
of
avoided
losses
in
commercially
valuable
timber
and
aesthetic
losses
suffered
by
non­
consumptive
users.
170
REFERENCES
1.
U.
S.
Environmental
Protection
Agency.
Regulatory
Impact
Analysis
for
the
National
Emissions
Standards
for
Hazardous
Air
Pollutants
for
Source
Categories:
Organic
Hazardous
Air
Pollutants
from
the
Synthetic
Organic
Chemical
Manufacturing
Industry
and
Seven
Other
Processes.
Draft
Report.
Office
of
Air
Quality
Planning
and
Standards.
Research
Triangle
Park,
NC.
EPA­
450/
3­
92­
009.
December
1992.

2.
Mathtech,
Inc.
Benefit
Analysis
Issues
for
Section
112
Regulations.
Final
report
prepared
for
U.
S.
Environmental
Protection
Agency.
Office
of
Air
Quality
Planning
and
Standards.
Contract
No.
68­
D8­
0094.
Research
Triangle
Park,
NC.
May
1992.

3.
U.
S.
Environmental
Protection
Agency.
Cancer
Risk
from
Outdoor
Exposure
to
Air
Toxics.
Volume
I.
EPA­
450/
1­
90­
004a.
Office
of
Air
Quality
Planning
and
Standards.
Research
Triangle
Park,
NC.
September
1990.

4.
Graham,
John
D.,
D.
R.
Holtgrave,
and
M.
J.
Sawery.
"
The
Potential
Health
Benefits
of
Controlling
Hazardous
Air
Pollutants."
In:
Health
Benefits
of
Air
Pollution
Control:
A
Discussion.
Blodgett,
J.
(
ed).
Congressional
Research
Service
report
to
Congress.
CR589­
161.
Washington,
DC.
February
1989.

5.
Reference
4.

6.
Voorhees,
A.,
B.
Hassett,
and
I.
Cote.
Analysis
of
the
Potential
for
Non­
Cancer
Health
Risks
Associated
with
Exposure
to
Toxic
Air
Pollutants.
Paper
presented
at
the
82nd
Annual
Meeting
of
the
Air
and
Waste
Management
Association.
1989.

7.
Reference
4.

8.
Reference
6.

9.
Cote,
I.,
L.
Cupitt
and
B.
Hassett.
Toxic
Air
Pollutants
and
Non­
Cancer
Health
Risks.
Unpublished
paper
provided
by
B.
Hassett.
1988.

10.
NAS.
Chlorine
and
Hydrogen
Chloride.
National
Academy
of
Sciences,
National
Research
Council.
Chapter
7.
1975.

11.
Stern,
A.
et
al.
Fundamentals
of
Air
Pollution.
Academic
Press,
New
York.
1973.

12.
Weinstein,
D.
and
E.
Birk.
The
Effects
of
Chemicals
on
the
Structure
of
Terrestrial
Ecosystems:
Mechanisms
and
Patterns
of
Change.
In:
Levin,
S.
et
al.
(
eds).
REFERENCES
(
continued)

171
Ecotoxicology:
Problems
and
Approaches.
Chapter
7.
pp.
181­
209.
Springer­
Verlag,
New
York.
1989.

13.
Reference
1.
p.
3­
5.

14.
Reference
1.
pp.
8­
4
to
8­
5.

15.
U.
S.
Environmental
Protection
Agency.
Ecological
Exposure
and
Effects
of
Airborne
Toxic
Chemicals:
An
Overview.
EPA/
6003­
91/
001.
Environmental
Research
Laboratory.
Corvallis,
OR.
1991.

16.
Reference
4.

17.
Reference
1.
pp.
8­
8
to
8­
9.
172
8.0
QUANTITATIVE
ASSESSMENT
OF
BENEFITS
This
chapter
presents
quantitative
estimates
of
the
possible
dollar
magnitude
of
the
benefits
identified
in
the
previous
chapter.
The
quantification
of
dollar
benefits
for
all
benefit
categories
is
not
possible
at
this
time
because
of
limitations
in
both
data
and
methodology.
This
chapter
presents
the
methodology
which
was
utilized
to
obtain
monetary
estimates
of
HAP
and
VOC
emission
reductions
occurring
as
a
result
of
the
proposed
rule.

Limitations
of
this
methodology
are
also
identified.
To
ensure
that
an
economically
efficient
regulatory
alternative
is
chosen,

an
incremental
analysis
must
be
performed.
Therefore,
benefits
for
the
two
regulatory
alternatives
are
presented.
Potential
impacts
are
evaluated
for
the
promulgated
regulation
and
one
alternative
more
stringent
than
that.

8.1
METHODOLOGY
FOR
DEVELOPMENT
OF
BENEFIT
ESTIMATES
Quantification
of
impacts
associated
with
HAP
exposure
requires
information
on
the
particular
HAP
involved.
Such
data
are
necessary
because
different
HAP
emissions
can
lead
to
different
types
and
degrees
of
severity
of
impacts.
Table
8­
1
identifies
the
specific
HAPs
emitted
by
petroleum
refineries.

Although
an
estimate
of
the
total
reduction
in
HAP
emissions
for
various
control
options
has
been
developed
for
this
RIA,
it
has
not
been
possible
to
estimate
specific
HAP
emission
reductions
for
each
type
of
emission
point.
However,
an
estimate
of
HAP
speciation
for
equipment
leaks
has
been
made.
Since
HAP
emissions
from
equipment
leaks
account
for
nearly
two
thirds
of
total
HAP
emissions
at
petroleum
refineries,
it
is
possible
to
use
these
data
to
develop
a
rough
estimate
of
cancer
risk
related
to
petroleum
refinery
emissions
of
benzene.

The
potential
impacts
of
reducing
HAP
emissions
can
be
separated
into
two
health
benefits
categories.
The
first
health
benefit
category
evaluated
will
be
the
reduction
in
annual
cancer
173
incidence
due
to
carcinogenic
HAP
emission
reductions.
This
approach
uses
emissions
data
and
the
Human
Exposure
Model
(
HEM)

to
estimate
the
annual
cancer
risk
caused
by
HAP
emissions
from
petroleum
refineries.
Generally,
this
benefit
category
is
calculated
as
the
difference
in
estimated
annual
cancer
incidence
before
and
after
implementation
of
each
regulatory
alternative.

The
benefit
category
is
then
monetized
by
applying
a
range
of
benefit
values
for
each
cancer
case
avoided.

The
second
category
of
health
benefits
expected
to
result
from
reduced
HAP
emissions
is
reduced
human
exposure
to
noncarcinogenic
HAP
emissions.
For
each
noncarcinogenic
HAP
for
which
EPA
had
health
benchmark
information,
EPA
performed
a
baseline
assessment
to
estimate
the
number
of
people
exposed
to
HAPs
above
health
benchmark
levels.
The
quantified
benefits
attributable
to
reducing
noncarcinogenic
HAP
emissions
is
the
difference
in
the
number
of
people
exposed
above
health
benchmark
levels
before
and
after
regulation.
The
benefits
of
controlling
VOC
emissions
are
monetized
by
applying
average
benefit
per
Megagram
estimates
to
the
total
amount
of
VOC
emission
reductions
calculated
for
each
of
the
two
regulatory
alternatives.

8.1.1
Benefits
of
Reduced
Cancer
Risk
Associated
with
HAP
Reductions
The
proposed
MACT
for
petroleum
refineries
is
expected
to
reduce
the
emissions
of
several
HAPs
that
have
been
classified
as
probable
or
known
human
carcinogens.
As
a
result,
one
of
the
benefits
of
the
final
regulation
is
a
reduction
in
the
risk
of
cancer
mortality.

TABLE
8­
1.
HAP
EMISSIONS
AT
PETROLEUM
REFINERIES
2,2,4
­
Trimethyl
Pentane
Hydrogen
Fluoride
Benzene
Phenol
Ethyl
Benzene
Cresols/
Cresylic
Acid
Hexane
Methyl
Tertiary
Butyl
Ether
Naphthalene
Hydrogen
Chloride
Toluene
Methyl
Ethyl
Ketone
Xylenes
174
A
quantitative
assessment
of
these
benefits
requires
two
types
of
data.
First,
it
must
be
possible
to
relate
changes
in
emissions
to
changes
in
risk
and
incidence
of
cancer.
This
involves
the
completion
of
a
risk
assessment.
The
second
type
of
data
required
to
estimate
the
economic
benefits
of
reduced
cancer
risk
is
an
estimate
of
society's
willingness
to
pay
to
realize
this
risk
reduction.
While
straightforward
in
concept,
there
are
difficulties
in
the
way
both
types
of
data
are
usually
developed
so
that
the
credibility
of
any
quantitative
estimates
must
be
carefully
assessed.
The
next
two
sections
discuss
the
models
of
cancer
risk,
and
estimates
of
the
value
of
a
statistical
life.

8.1.1.1
Models
of
Cancer
Risk.
A
variety
of
models
have
been
proposed
to
formalize
the
relationships
between
emission
changes
and
changes
in
cancer
risk
so
that
predictions
can
be
made
regarding
changes
in
the
expected
number
of
lives
saved
due
to
a
specific
emission
reduction
scenario.
Cancer
risk
models
often
express
cancer
risk
in
terms
of
excess
lifetime
cancer
risk.

Lifetime
risk
is
a
measure
of
the
probability
that
an
individual
will
develop
cancer
as
a
result
of
exposure
to
an
air
pollutant
over
a
lifetime
of
70
years.
1
A
basis
for
developing
estimates
of
this
probability
is
the
unit
risk
factor
(
URF).
The
URF
is
a
quantitative
estimate
of
the
carcinogenic
potency
of
a
pollutant.

It
is
often
expressed
as
the
probability
of
contracting
cancer
from
a
70
year
lifetime
continuous
exposure
to
a
concentration
of
one
microgram
per
cubic
meter
(
µ
g/
m3)
of
a
pollutant.
The
unit
risk
factors
are
designed
to
be
conservative.
That
is,
actual
risk
may
be
higher,
but
it
is
more
likely
to
be
lower.
EPA
has
developed
unit
risk
factors
for
many
HAPs.
1
Among
the
HAPs
identified
in
Table
8­
1,
only
benzene
and
cresols
have
quantitative
URFs.
In
addition,
benzene
is
a
known
human
carcinogen,
as
there
are
several
studies
linking
benzene
exposure
to
cancer
in
humans.
Cresols
are
considered
possible
human
carcinogens
based
on
animal
experiments.
175
To
translate
lifetime
individual
risk
to
annual
incidence
of
excess
cancer,
it
is
necessary
to
combine
three
pieces
of
data:

the
unit
risk
factor,
the
(
constant)
level
of
concentration
to
which
the
population
is
exposed,
and
the
population
count.
For
example,
benzene,
which
is
classified
as
a
known
human
carcinogen,
has
a
unit
risk
factor
of
8.3
×
10­
6
(
µ
g/
m3)­
1.
In
a
population
of
1,000,000
people,
each
exposed
to
5
µ
g/
m3
of
benzene
for
70
years
(
a
lifetime
of
constant
exposure),
the
number
of
excess
cancer
cases
in
the
population
due
to
this
exposure
is
estimated
to
be
41.5
cancer
cases
over
70
years
(
5
µ
g/
m3
×
1,000,000
×
8.3
×
10­
6
(
µ
g/
m3)­
1).
On
an
annual
average
basis,
this
is
equal
to
0.59
excess
cases
per
year
in
the
population.

From
the
above
example
calculation,
it
is
clear
that
each
element
in
the
calculation
algorithm
may
contribute
to
uncertainty
in
the
final
estimate
of
cancer
risk.
Table
8­
2
summarizes
the
major
sources
of
uncertainty
with
the
data
and
methods
used
in
the
standard
approach
to
cancer
risk
assessment.

Additional
issues
arise
in
estimating
economic
benefits
from
the
risk
assessment
information.
Table
8­
3
identifies
these
issues.

8.1.1.2
Value
of
a
Statistical
Life.
Economists
have
used
labor
market
data
to
identify
the
wage­
risk
tradeoff
accepted
by
workers
in
high
risk
occupations
and
to
infer
the
implicit
value
of
a
statistical
life.
Multiplication
of
the
value
of
a
statistical
life
times
the
expected
number
of
lives
saved
due
to
the
reduced
cancer
risk
provides
an
estimate
of
the
economic
benefits
associated
with
the
regulation.
Estimates
of
the
value
of
a
statistical
life
have
been
developed
by
examining
the
wagerisk
tradeoff
revealed
by
workers
accepting
jobs
with
known
risks.
Viscusi
recently
completed
a
survey
of
over
20
of
these
studies
and
recommends
an
initial
range
of
$
3­$
7
million
(
December
1990
dollars)
as
an
estimate
of
the
statistical
value
of
a
life.
2
Using
this
range
in
an
environmental
policy
analysis
requires
consideration
of
several
factors
that
could
bias
the
transfer
of
176
the
results.
Specifically,
adjustments
may
be
required
to
account
for
differences
across
applications.
These
differences
include:


Risk
perception:
Environmental
risks
are
involuntary;
job
risks
may
not
be.
Cancer
risks
may
be
prolonged
and
involve
suffering;
job
fatalities
may
be
more
immediate
in
consequence.


Age:
The
age
of
the
affected
population
may
affect
willingness
to
pay
values.
Life
years
saved
may
be
a
more
relevant
measure.
Discount
rates
may
also
be
agesensitive


Income:
Income
levels
of
exposed
individuals
may
affect
willingness
to
pay.
Economic
theory
would
suggest
a
positive
elasticity
between
income
and
risk
reduction.


Baseline
risks:
The
willingness
to
pay
function
could
be
non­
linear.
Initial
risk
levels
and
the
change
in
risk
would
become
important
with
non­
linearities.
177
TABLE
8­
2.
SOURCES
OF
UNCERTAINTY
IN
CANCER
RISK
ASSESSMENT1

Unit
risk
factors
are
generally
derived
from
a
nonthreshold,
multi­
stage
model,
which
is
linear
at
low
doses.
Available
experimental
data
are
often
for
high
dose
exposures
so
that
responses
must
be
extrapolated
to
the
relatively
low
doses
typically
associated
with
ambient
conditions.


Unit
risk
information
is
frequently
generated
from
bioassays
in
which
the
potency
of
a
chemical
is
often
determined
by
the
effect
of
the
chemical
on
animals.
Transfer
of
results
across
species
is
subject
to
considerable
uncertainty.


Risk
estimates
are
calculated
as
if
exposed
individuals
experience
a
constant
outdoor
exposure
over
a
lifetime.
This
ignores
activity
patterns
of
people
and
the
opportunity
for
behavioral
adjustments.


Estimates
of
exposure
are
often
conservative.
Ambient
concentrations
are
frequently
modeled
to
reflect
the
maximum
individual
risk
(
MIR)
(
i.
e.,
highest
concentration
location).
If
all
individuals
are
assumed
to
be
continuously
exposed
over
a
lifetime
to
the
concentration
associated
with
MIR,
this
will
bias
risk
estimates
upwards.


For
carcinogens
as
well
as
other
toxicants,
there
is
a
great
deal
of
individual
variability
in
sensitivity
to
adverse
effects.
In
some
cases,
the
suceptibility
of
an
individual's
reaction
to
a
toxic
pollutant
may
be
an
order
of
magnitude
of
greater
than
another's.
This
increaes
the
uncertainty
of
cancer
risk
estimates
at
both
the
individual
and
population
level.

TABLE
8­
3.
UNCERTAINTIES
IN
BENEFIT
ANALYSIS
178

Benefit
calculations
should
reflect
the
year­
by­
year
change
in
cancer
incidence
following
policy
implementation.
The
timing
of
incidences,
including
latency
periods,
should
be
expressly
considered.


Benefit
calculations
should
reflect
changes
in
concentrations
over
time
related
to
economic
responses
to
the
regulatory
action.


Benefit
calculations
should
reflect
any
changes
to
the
composition
of
the
affected
population
and
possible
behavioral
responses
to
exposure.


Valuation
of
cancer
incidences
should
address
a
variety
of
issues.
These
include:
discounting,
age
distribution,
non­
voluntary
nature
of
risk,
risk
adverseness
of
general
population,
probability
of
fatality,
and
treatment
costs.
179
180
Unfortunately,
there
is
no
general
consensus
on
the
adjustments
that
should
be
made
to
account
for
these
possible
biases
in
a
direct
transfer
of
values.
As
a
result,
this
study
makes
no
adjustments
other
than
to
update
the
values
to
first
quarter
1992
dollars.
With
this
single
change,
the
value
range
to
be
applied
to
the
annual
reduction
in
lives
saved
is
$
3.11­

$
7.25
million.

8.1.1.3
Quantitative
Results.
Emissions
of
benzene
and
naphthalene
were
input
into
the
HEM
to
conduct
a
risk
and
exposure
assessment
of
baseline
HAP
emissions.
One
important
input
to
the
HEM
was
the
URF
of
each
pollutant.
The
URFs
are
presented
in
Table
8­
4.

TABLE
8­
4.
UNIT
RISK
FACTORS
FOR
CARCINOGENIC
HAPS
HAP
URF
(
x
106)

Benzene
8.3
Naphthalene
4.2
The
HEM
uses
the
URFs
in
Table
8­
4,
along
with
other
information
such
as
refinery
emissions,
to
characterize
the
risk
posed
to
individuals
and
the
population
located
within
a
50
km
radius
of
each
refinery
(
approximately
83.4
million
people).

The
maximum
individual
risk
(
MIR)
and
annual
cancer
incidence
for
the
two
HAPs
are
presented
in
Table
8­
5.
The
MIR
for
each
pollutant
expresses
the
increased
risk
experienced
by
the
person
exposed
to
the
highest
predicted
concentration
of
each
HAP.
The
values
in
Table
8­
5
are
for
emissions
at
the
baseline
only.
The
annual
cancer
incidences
are
the
number
of
new
cancer
cases
estimated
to
occur
in
the
exposed
population
as
a
result
of
a
year's
exposure.
As
estimated
by
HEM,
the
total
annual
cancer
incidence
of
the
2
HAPs
is
0.52
of
a
statistical
life.
Because
181
the
cancer
risk
associated
with
benzene
and
naphthalene
is
less
than
1,
the
quantifiable
cancer
benefits
of
reduced
emissions
are
expected
to
be
minimal.
The
benefits
of
reducing
cancer
risk
resulting
from
reduced
emissions
of
carcinogenic
HAPs
could
not
be
monetized
since
values
of
annual
cancer
risk
after
controls
were
not
available.
However,
if
it
is
assumed
that
the
controls
required
by
the
proposed
rule
would
decrease
benzene
and
naphthalene
emissions
to
zero,
then
a
monetary
estimate
of
the
benefit
of
reducing
these
two
HAPs
could
be
calculated.
The
benefit
of
eliminating
the
carcinogenic
HAP
emissions
is
calculated
by
multiplying
the
0.52
reduction
in
total
annual
cancer
risk
by
the
midpoint
of
the
range
of
values
of
a
statistical
life
($
3.11
to
$
7.25
million)
which
is
$
5.2
million.

This
calculation
yields
a
total
monetary
benefit
of
$
2.7
million.

This
is
an
overestimation,
however,
given
that
the
petroleum
refinery
NESHAP
will
not
achieve
a
100
percent
HAP
reduction.

TABLE
8­
5.
MAXIMUM
INDIVIDUAL
RISK
AND
ANNUAL
CANCER
INCIDENCE
OF
CARCINOGENIC
HAPs
HAP
MIR
Annual
Cancer
Incidence
Benzene
1.8
x
10­
4
0.37
Naphthalene
6.8
x
10­
5
0.15
These
monetary
values
should
be
interpreted
carefully
due
to
uncertainties
in
the
derivation
of
annual
incidence
numbers,
the
value
of
life
estimates,
and
the
focus
on
equipment
leak
emissions.
Because
these
uncertainties
work
in
both
directions,

and
remain
unquantified,
it
is
not
possible
to
say
whether
these
values
are
over­
or
underestimates
of
the
(
unknown)
true
value
of
cancer
risk
reduction.
At
best,
the
numbers
should
be
viewed
as
a
guide
to
the
possible
level
of
benefits
that
may
be
realized.

8.1.1.4
Other
Health
and
Welfare
Impacts
of
HAPs.
A
quantitative
assessment
of
the
economic
benefits
related
to
these
182
impacts
requires
information
on
risk
relationships,
exposure,
and
economic
value.
Unfortunately,
such
data
are
generally
unavailable.
Therefore,
it
is
currently
not
possible
to
conduct
a
complete
quantitative
analysis
of
the
benefits
associated
with
HAP
emission
reductions.

Several
intermediate
quantitative
assessment
approaches
have
been
developed
which
can
provide
partial
objective
evidence
of
the
positive
impact
of
HAP
emission
reductions.
One
approach
examines
changes
in
the
population
exposed
to
concentrations
of
HAPs
over
a
reference
dose
level
with
and
without
additional
controls.
3
The
reference
concentration
(
RfC)
is
designed
to
reflect
a
concentration
level,
within
an
order
of
magnitude,
at
which
no
adverse
health
impacts
would
be
expected
over
a
lifetime.
To
complete
this
calculation,
data
must
be
available
on
population
counts
near
affected
refineries,
concentrations
of
speciated
HAPs
with
and
without
additional
controls,
and
a
reference
dose
level
for
the
specific
HAP.

Based
on
toxicity
and
emission
information,
an
exposure
assessment
was
performed
for
hexane,
hydrogen
chloride,

methylethyl
ketone,
and
toluene.
For
noncarcinogens
endpoints,

the
dose­
response
is
expressed
in
terms
of
an
inhalation
reference­
dose
concentration
(
RfC).
The
significance
of
the
RfC
benchmark
is
that
exposures
to
levels
below
the
RfC
are
considered
"
safe"
because
exposures
to
concentrations
of
the
chemical
at
or
below
the
RfC
are
less
than
where
adverse
effects
are
thought
to
occur.
The
RfCs
of
the
above
mentioned
HAPs
are
presented
in
Table
8­
6.
The
benefits
of
reducing
these
HAPs
could
not
be
monetized
because
information
on
reduced
exposure
is
not
available.
The
omission
of
this
benefit
category
from
the
monetized
benefits
analysis
will
lead
to
an
underestimation
of
the
total
expected
benefits
from
the
proposed
regulation.
183
Significant
baseline
exposure
was
not
shown
to
result
from
these
HAPs,
so
post­
regulation
emissions
were
not
analyzed.

TABLE
8­
6.
RFCS
AND
NUMBER
OF
INDIVIDUALS
EXPOSED
AT
OR
ABOVE
RFC
BY
HAP
HAP
RfC
Individuals
Exposed
At
or
Above
RfC
Hexane
0.2
mg/
M3
0
Hydrogen
Chloride
0.07
mg/
M3
1,810
Methyl
Ethyl
Ketone
1
mg/
M3
0
Toluene
0.4
mg/
M3
0
Epidemiological
studies
which
attempt
to
identify
statistical
associations
between
exposure
and
observable
responses
in
the
population
represent
another
way
to
quantify
possible
risks.

However,
because
of
collinearity
with
other
environmental
factors,
difficulty
in
measuring
some
health
outcomes,
and
the
large
cohort
sizes
needed
to
be
followed
over
time
to
find
statistically
significant
relationships,
it
is
very
difficult
to
isolate
the
effects
due
solely
to
changes
in
HAP
emissions.
For
this
reason,
such
statistical
functions
have
generally
not
been
estimated.

In
addition
to
health
effects
associated
with
chronic
or
longterm
exposures
to
HAPs,
there
are
also
many
HAPs
that
are
associated
with
adverse
effects
from
short­
term,
or
acute,

exposures.
For
example,
emissions
of
hydrogen
fluoride
have
been
responsible
for
injuries
and
even
deaths
at
petroleum
refineries.
9
To
the
extent
that
the
petroleum
refinery
NESHAP
controls
emissions
of
short­
term
releases
associated
with
adverse
health
effects
(
either
by
controls
or
pollution
prevention),

there
will
be
associated
benefits.
Unfortunately,
methods
to
estimate
these
benefits
are
not
currently
available.
184
At
present,
most
of
the
model
development
in
the
area
of
estimating
the
welfare
effects
and
ecosystem
impacts
of
exposure
to
HAPs
is
still
conceptual
and
not
amenable
to
objective
measurement.
Therefore,
no
quantitative
estimates
of
these
potential
ecosystem
impacts
have
been
made.

8.1.2
Quantitative
Benefits
of
VOC
Reduction
The
benefits
of
reduced
emissions
of
VOC
from
a
MACT
regulation
of
petroleum
refineries
will
be
developed
using
the
technique
of
"
benefits
transfer."
Benefits
transfer
involves
the
use
of
benefit
values
obtained
from
another
study
to
represent
benefits
associated
with
the
current
regulatory
proposal,
with
appropriate
adjustments.
At
a
minimum,
the
adjustments
must
address
the
differential
impact
in
the
severity
of
the
regulations
as
represented,
for
example,
by
changes
in
emissions
or
concentrations.
With
this
technique
the
assumption
is
made
that
benefits
per
ton
reduced
of
a
pollutant
are
constant.
Then,

estimates
of
a
benefit
per
ton
reduced
ratio
from
a
prior
study,

coupled
with
information
on
tons
reduced
for
the
regulation
under
review,
will
be
sufficient
to
estimate
benefits
for
the
current
regulation.
In
effect,
extrapolated
benefits
are
developed
on
the
basis
of
a
constant,
average
benefit
per
ton
reduced
value.

In
this
RIA,
an
estimate
of
the
benefits
per
(
metric)
ton
reduced
of
VOC
emissions
is
developed
from
a
study
conducted
for
the
Office
of
Technology
Assessment.
4
The
OTA
study
examined
a
variety
of
acute
health
impacts
related
to
ozone
exposure
as
well
as
the
benefits
of
reduced
ozone
concentrations
for
selected
agricultural
crops.
However,
chronic
health
effects
of
ozone
exposure,
as
well
as
effect
on
non­
agricultural
vegetation,
were
not
considered.
Therefore,
all
else
equal,
the
extrapolated
estimate
of
VOC
benefits
for
the
MACT
regulation
should
be
viewed
as
a
lower
bound
estimate.

8.1.2.1
Benefit
Transfer
Values.
Application
of
the
benefit
transfer
technique
requires
information
on
benefit
values
and
the
185
associated
reduction
in
VOC
emissions.
Data
on
benefits
are
taken
from
Table
3­
10
of
the
OTA
report.
For
the
present
calculation,
the
values
reported
for
the
35
percent
VOC
reduction
scenario
are
used.
Specifically,
information
from
both
the
epidemiological
studies
and
the
clinical
studies
is
used
to
establish
an
initial
benefit
range
of
$
54­$
3,400
million
per
year.

The
selection
of
this
range
of
values
was
influenced
by
several
factors.
First,
the
results
for
the
35
percent
VOC
emission
reduction
scenario
are
used
because
it
is
easier
to
identify
the
level
of
emission
reductions
associated
with
this
scenario
in
the
OTA
report.
It
should
also
be
noted
that
this
scenario
involves
a
reduction
of
35
percent
in
those
emissions
occurring
only
in
non­
attainment
areas.
Although
there
are
expected
to
be
VOC
emission
reductions
in
attainment
areas
under
this
scenario,
the
percentage
reduction
in
VOC
emissions
in
attainment
areas
is
less
than
35
percent.
A
close
reading
of
the
OTA
report
indicates
that
all
health
impacts
are
estimated
for
non­
attainment
areas
only.
Therefore,
no
benefits
are
associated
with
VOC
emission
reductions
in
attainment
areas.
This
may
provide
additional
conservatism
to
the
benefit
values
since
there
is
recent
evidence
that
acute
health
effects
may
be
experienced
at
ozone
concentrations
below
the
current
NAAQS.
5
The
OTA
report
calculates
acute
health
impacts
based
on
the
results
of
epidemiological
and
clinical
studies.
Both
study
designs
have
advantages
and
disadvantages
relative
to
one
another.
Indeed,
the
OTA
report
acknowledges
that
it
is
not
possible
to
judge
which
approach
is
superior.
Even
though
the
two
study
designs
measure
similar
impacts,
it
is
possible
to
use
the
results
from
both
design
types
to
form
a
range
of
values.

This
approach
would
not
involve
double­
counting
and
would
use
more
of
the
available
information.
A
lower
bound
value
is
identified
from
the
epidemiological
study
design.
An
upper
bound
value
is
taken
from
the
clinical
study
design
in
which
all
aCPI
index
values
were
obtained
from
the
1993
U.
S.
Statistical
Abstract
(
Table
756)
and
the
December
1992
issue
of
the
Survey
of
Current
Business.

186
exercisers
are
affected.
These
choices
lead
to
the
initial
benefit
range
of
$
54­$
3,400
million
per
year.

The
year
of
dollars
for
these
benefit
values
is
not
made
clear
in
the
OTA
report.
However,
a
check
with
the
authors
of
several
of
the
cited
references
used
to
develop
"
willingness­
to­
pay"

values,
indicates
that
the
values
are
in
1984
dollar
terms.
6
To
maintain
consistency
with
other
parts
of
this
RIA,
the
benefit
values
are
converted
to
first
quarter
1992
dollars
by
multiplying
the
1984
dollars
by
a
factor
of
1.335.
This
factor
was
computed
from
the
percentage
change
in
the
all
item
urban
CPI
index
between
the
annual
index
value
for
1984
and
the
geometric
mean
of
index
values
for
the
first
three
months
of
1992.
a
The
adjusted
dollar
benefit
range
in
first
quarter
1992
dollars
is
$
72­$
4,539
million.

Three
further
adjustments
can
be
considered
for
this
benefit
value
range.
First,
as
noted
earlier,
benefits
can
be
scaled
by
the
tons
of
VOC
emissions
reduced
in
order
to
form
a
benefit
transfer
ratio
which
can
be
multiplied
by
the
VOC
emission
reductions
for
the
petroleum
refinery
MACT.

Second,
the
benefit
values
in
the
OTA
report
reflect
a
level
of
exposure
that
corresponds
to
population
densities
in
nonattainment
areas
in
the
early
1980'
s.
Since
the
cost
analysis
is
conducted
for
the
fifth
year
following
rule
promulgation
(
i.
e.,

circa
1999),
the
benefit
analysis
should
be
conformable.
There
is
approximately
a
twenty
year
interval
from
the
period
when
the
estimates
used
in
the
OTA
report
were
calculated
to
the
year
of
regulatory
impact.
It
is
appropriate
to
scale
the
OTA
benefit
values
by
a
factor
which
represents
the
percentage
change
in
population,
between
1980
and
1999,
in
those
non­
attainment
areas
with
petroleum
refineries.
Using
data
from
the
1980
and
1990
Censuses
and
extrapolating
to
1999
under
an
assumption
of
a
bStatistical
Abstract,
1993,
Table
704.

cThe
emissions
data
in
OTA
do
not
reflect
measured
emissions.
Rather,
they
represent
emissions
on
a
typical
non­
attainment
day
multiplied
by
365.
It
is
not
clear
from
OTA
how
these
"
nonattainment­
day­
equivalent­
annualemissions
are
calculated
for
attainment
regions.

187
constant
growth
rate
equal
to
that
observed
for
the
10
year
period,
it
is
estimated
that
the
population
scale
factor
is
19.64
percent.
This
leads
to
a
revised
benefit
value
range
of
$
86
to
$
5,430
million.

Third,
the
passage
of
time
may
also
affect
the
willingness
to
pay
value.
If
real
income
grows
over
time
and
the
income
elasticity
of
environmental
quality
is
positive,
then
unit
willingness
to
pay
values
in
1999
should
exceed
those
implied
by
the
surveys
conducted
in
the
mid­
1980'
s.
Using
the
1993
Statistical
Abstractb,
the
simple
average
percentage
change
in
per
capita
real
income
between
1985
and
1992
is
3.3
percent
in
those
areas
most
likely
to
be
ozone
non­
attainment
areas.

Extrapolating
to
1999
under
a
constant
growth
assumption
results
in
an
increase
of
6.7
percent.
Given
this
relatively
small
change
and
uncertainty
about
the
proper
income
elasticity
measure,
no
adjustment
has
been
made
to
the
benefit
value
range
to
account
for
this
factor.

8.1.2.2
Emission
Reductions.
The
development
of
VOC
emission
reductions
associated
with
the
benefits
range
described
above
can
be
determined
directly
from
the
OTA
report.
Tables
6­
1
and
6­
6
of
OTA
provide
the
needed
information.
Total
VOC
emissions
in
1985
are
25
million
tons.
c
Of
this
total,
11
million
tons
are
predicted
to
occur
in
non­
attainment
cities
while
14
million
tons
of
VOC
are
predicted
to
be
emitted
in
ozone
attainment
areas.

For
the
35
percent
VOC
(
non­
attainment
area)
emission
reduction
scenario,
3.8
million
tons
of
VOC
emissions
are
predicted
to
be
controlled
in
1994,
while
2.7
million
tons
will
be
controlled
in
attainment
areas.
dRecent
evidence
suggests
that
some
health
benefits
may
occur
for
VOC
emission
reductions
in
areas
near,
but
below,
the
current
ozone
NAAQS.
5
As
might
be
expected,
the
response
rate
is
lower
than
that
observed
at
higher
ozone
concentrations.
In
addition,
economic
theory
suggests
that
the
marginal
willingness
to
pay
for
an
incremental
improvement
in
air
quality
at
such
levels
would
be
less
than
the
marginal
willingness
to
pay
for
increments
at
a
higher
level
above
the
standard.
That
is,
the
marginal
benefits
function
is
non­
linear.
Since
the
benefit
transfer
ratio
assumes
a
constant,
linear
relationship,
it
seems
prudent
to
limit
the
benefits
transfer
calculation
to
the
non­
attainment
area
data
presented
in
the
OTA
report.

188
The
selection
of
a
"
tons
reduced"
value
for
the
denominator
of
the
benefit
transfer
ratio
must
be
consistent
with
the
benefits
measure
selected
for
the
numerator.
As
described
earlier,
the
benefits
reflect
the
annual
reduction
in
acute
health
impacts
experienced
by
populations
in
non­
attainment
areas
that
result
from
a
35
percent
reduction
in
non­
attainment
area
VOC
emissions.

Implicitly,
there
is
the
assumption
that
no
health
benefits
are
experienced
in
attainment
areas.
Consequently,
it
seems
most
appropriate
to
define
the
VOC
emission
reductions
in
terms
of
reductions
occurring
only
in
non­
attainment
areas.
This
also
implies
that
the
derivation
of
petroleum
refinery
health
benefits
from
VOC
emission
reductions
should
consider
only
those
emission
reductions
which
occur
at
plants
in
non­
attainment
areas.

Fortunately,
because
individual
refineries
are
identified,
it
is
possible
to
identify
this
subset
of
emission
reductions.
A
result
of
this
approach
is
that
no
acute
health
benefits
are
associated
with
VOC
emission
reductions
in
attainment
areas.
d
Table
8­
7
presents
the
baseline
VOC
emissions,
and
the
emission
reductions
for
refineries
in
nonattainment
areas
associated
with
each
alternative.
189
TABLE
8­
7.
VOC
EMISSION
REDUCTIONS
BY
EMISSION
POINT
VOC
Emission
Reductions
by
Regulatory
Alternative
(
Mg/
yr)
3
Alternative
1
Alternative
2
Emission
Point2
Nonattainment1
Attainment
Nonattainment1
Attainment
Equipment
Leaks
77,535
80,266
81,626
83,471
Miscellaneous
Process
Vents
104,693
55,161
104,693
55,161
Storage
Vessels
3,090
1,408
6,056
2,760
TOTAL
REDUCTION
BY
ATTAINMENT
STATUS
185,318
136,835
192,375
141,392
TOTAL
REDUCTION
BY
ALTERNATIVE
322,153
333,767
NOTES:
1VOC
emission
reductions
include
only
those
associated
with
control
of
the
87
refineries
located
in
ozone
nonattainment
areas.
2No
further
control
is
assumed
for
wastewater
streams,
and
therefore,
emission
reductions
associated
with
this
emission
point
are
zero.
3Emission
reduction
estimates
do
not
incorporate
reduction
occurring
at
new
sources.

One
final
step
is
needed
prior
to
forming
the
benefit
transfer
ratio.
Since
VOC
emission
reductions
for
petroleum
refineries
are
stated
in
megagrams
per
year
(
metric
tons
per
year),
it
is
necessary
to
convert
the
OTA
emission
reductions
to
equivalent
metric
tons.
This
conversion
results
in
a
reduction
of
3.45
million
metric
tons
in
non­
attainment
areas.

8.1.2.3
Benefit
Estimates.
The
benefit
transfer
ratio
range
for
acute
health
impacts
is
estimated
to
be
$
25­$
1,574
(
first
quarter
1992
dollars
per
metric
ton).
These
values
were
obtained
by
dividing
the
benefit
range
values
by
the
reduction
in
emissions.
The
average
(
mid­
point)
of
the
range
is
$
800
per
metric
ton.

These
ratios
are
to
be
multiplied
by
VOC
emission
reductions
from
petroleum
refineries
located
in
ozone
non­
attainment
areas
in
order
to
estimate
the
VOC­
related
acute
health
benefits
of
the
petroleum
refinery
MACT.
Table
8­
8
summarizes
the
results
of
these
calculations
for
the
combination
of
options
selected
for
the
four
controlled
emission
points.
In
addition,
benefits
for
the
next
most
stringent
option
for
each
emission
point
type
are
also
reported.
Note,
the
floor
option
for
each
emission
point
type
is
statutorily
mandated
so
that,
in
effect,
the
floor
options
represent
the
baseline.

TABLE
8­
8.
BENEFITS
OF
VOC
REDUCTIONS
BY
REGULATORY
ALTERNATIVE
(
4)

Benefits
(
Million
Dollars)

Alternative
1
Alternative
2
Average
$
148.3
$
153.9
Range
$
4.6
­
$
291.7
$
4.8
­
$
302.8
190
The
benefit
values
reported
above
are
restricted
to
acute
health
impacts
associated
with
VOC
emission
reductions.
Several
qualifications
should
be
noted.
First,
there
is
an
implicit
assumption
of
a
constant
linear
relationship
between
VOC
emission
reductions
and
changes
in
ozone
concentrations
in
nonattainment
areas.
One
result
of
this
assumption
is
that
it
becomes
difficult
to
justify
quantifying
benefits
for
agricultural
yield
changes
associated
with
VOC
emission
reductions.
As
described
in
OTA,
the
VOC/
NOx
ratio
in
rural
areas
is
NOx­
limited
because
of
relatively
high
vegetative
VOC
emissions.
7
Consequently,
ozone
production
is
less
sensitive
to
changes
in
man­
made
VOC
emissions.
Therefore,
it
seems
appropriate
to
exclude
agricultural
benefits
for
the
present
analysis.

Also,
as
noted
earlier,
there
may
be
other
benefit
types.
Reductions
in
VOC
emissions
which
lead
to
improvements
in
ozone
concentrations
may
contribute
to
reductions
in
chronic
health
impacts
(
e.
g.,

sinusitis,
hay
fever
and
reduced
damage
to
certain
materials,
such
as
elastomers).
8
However,
because
of
data
and
methodological
concerns,
no
quantitative
benefit
estimates
for
these
possible
effect
types
have
been
developed
for
the
present
analysis.
All
else
equal,
this
implies
that
the
calculated
benefit
per
metric
ton
range
of
$
25­$
1,574
is
likely
to
be
conservative.

Although
the
quantified
VOC
benefits
estimated
in
this
RIA
represent
one
approach
for
valuing
the
benefits
of
reduced
VOC
emissions,
data
limitations
prevent
a
complete
quantification
of
all
categories
of
benefits
attributable
to
VOC
reductions.
Since
lack
of
data
prevent
all
benefit
categories
from
being
monetized,
a
direct
comparison
of
benefits
to
costs
may
not
be
helpful
in
determining
the
desirable
regulatory
alternative.
An
assessment
of
the
incremental
cost­
effectiveness
analysis
will
represent
the
cost
of
the
air
emission
controls
relative
to
the
expected
VOC
emission
reductions
attributable
to
the
controls.

Because
of
the
lack
of
data,
this
analysis
ignores
the
benefit
of
HAP
emission
reductions.
The
incremental
VOC
cost­
effectiveness
analysis
begins
with
the
baseline,
or
no
control.
Alternative
1,
which
is
the
basis
of
the
proposed
rule,
includes
controls
to
meet
MACT
floor
level
controls,
and
a
level
of
control
more
stringent
than
the
floor
for
equipment
leaks.
The
total
cost
of
this
control
is
$
132
million
annually.
This
regulatory
alternative
is
expected
to
result
in
a
reduction
of
VOC
emissions
of
approximately
185,000
Mg
annually.
Therefore,
the
incremental
cost­
effectiveness,
averaged
across
multiple
emission
points,
of
the
requirements
of
Alternative
1
is
approximately
$
712/
Mg.
In
other
words,
the
average
cost
of
reducing
each
Mg
required
by
Alternative
1
is
$
712.

The
next
more
stringent
level
of
control,
Alternative
2,
which
includes
increased
control
of
equipment
leaks
and
storage
vessels,
has
a
total
annual
cost
of
$
148
million.
This
level
of
control
is
estimated
to
achieve
an
annual
VOC
emission
reduction
of
approximately
192,375
Mg.
The
incremental
VOC
costeffectiveness
of
going
from
Alternative
1
to
Alternative
2
is
approximately
$
2,300/
Mg.

Table
8­
9
presents
the
incremental
VOC
cost­
effectiveness
values
for
each
regulatory
alternative
discussed
in
this
analysis.
Alternative
1
can
be
justified
as
a
desirable
option
since
the
incremental
VOC
cost­
effectiveness
of
implementing
Alternative
2
is
significantly
higher.
191
TABLE
8­
9.
VOC
INCREMENTAL
COST­
EFFECTIVENESS
OF
PETROLEUM
REFINING
REGULATION
Alternative
1
Alternative
2
Incremental
Cost
(
Million
$
1992)
1
$
132.35
$
16.0
Incremental
Emission
Reduction
(
Mg)
185,318
7,057
Incremental
Cost
Effectiveness
($/
Mg)
$
712/
Mg
$
2,267/
Mg
NOTES:
1The
cost
estimates
of
each
alternative
reflect
the
total
social
cost
of
emission
control.
192
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450/
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90­
004a.
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of
Air
Quality
Planning
and
Standards.
Research
Triangle
Park,
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September
1990.

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Viscusi,
W.
Kip.
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The
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Risks
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Life
and
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Journal
of
Economic
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1912­
1946.
December
1993.

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Voorhees,
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B.
Hassett,
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Potential
for
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Cancer
Health
Risks
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Exposure
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the
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Annual
Meeting
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the
Air
and
Waste
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1989.

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OTA­
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412.
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DC.
U.
S.
Government
Printing
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July
1989.

5.
Horstman,
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W.
McDonnell,
L.
Folinsbee,
S.
Abdal­
Salaam,
and
P.
Ives.
Changes
in
Pulmonary
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Airway
Reactivity
Due
to
Prolonged
Exposure
to
Typical
Ambient
Ozone
(
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Levels.
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Schneider,
T.
et
al.
(
eds.)
Atmospheric
Ozone
Research
and
its
Policy
Implications.
Elsevier
Science
Publishers.
Amsterdam.
1989.

6.
Horst,
R.
L.,
Jr.
Personal
communication
with
L.
Chestnut.
January
26,
1994.

7.
Reference
4.
p.
107.

8.
Portney
P.
and
J.
Mullahy.
"
Urban
Air
Quality
and
Chronic
Respiratory
Disease."
Regional
Science
and
Urban
Economics.
Vol.
20.
p.
407­
18.
1990.

9.
U.
S.
Environmental
Protection
Agency.
Hydrogen
Fluoride
Study:
Report
to
Congress
Under
Section
112(
n)(
6)
of
the
Clean
Air
Act
as
Amended;
Washington,
D.
C.;
EPA
550­
R­
93­
001.
September
1993
193
194
195
9.0
COMPARISON
OF
BENEFITS
TO
COSTS
The
goal
of
the
Regulatory
Impact
and
Benefits
Analysis
for
the
Petroleum
Refinery
NESHAP
is
to
provide
economic
and
engineering
data
necessary
for
effective
environmental
policymaking.
A
comparison
of
the
benefits
of
alternative
air
emission
controls
with
the
costs
of
such
controls
provides
the
necessary
framework
for
a
reasonable
assessment
of
the
net
benefits
of
the
proposed
environmental
measures.

9.1
COMPARISON
OF
ANNUAL
BENEFITS
AND
COSTS
The
potential
health
and
welfare
benefits
associated
with
air
emission
reductions
relate
to
expected
reductions
in
emissions
of
several
HAPs
and
VOCs
from
storage
tanks,
process
vents,
equipment
leaks,

and
wastewater
emission
points
at
refining
sites.
The
quantification
of
benefits
from
emission
controls
relates
to
health
benefits
from
reduced
cancer
incidence
associated
with
carcinogenic
HAPs
emitted
at
petroleum
refineries
and
the
health
benefits
related
to
reduced
VOCs
that
translate
into
reductions
in
ozone.

Benefits
from
reducing
cancer
incidence
to
zero
were
quantified
for
equipment
leaks
only
in
the
previous
chapter.
Because
of
the
uncertainty
associated
with
this
estimate,
the
benefits
of
reduced
cancer
risk
are
not
incorporated
in
this
benefit
cost
analysis.
Other
health
and
welfare
benefits
from
the
controls
such
as
benefits
to
the
ecosystem
have
not
been
quantified
due
to
limitations
in
data
and
methodology.

The
compliance
costs
of
the
alternative
emission
controls
relate
to
capital
costs
and
operation
and
maintenance
costs
for
each
of
the
regulatory
alternatives
obtained
from
engineering
studies
conducted
for
EPA.
These
estimates
reflect
the
engineering
costs
of
emission
controls
rather
than
the
economic
costs
to
society.
The
compliance
cost
estimates
provide
a
necessary
data
input
for
the
economic
analysis
of
the
cost
of
the
regulatory
alternatives
to
society.
The
economic
effect
of
imposing
compliance
costs
on
the
petroleum
refining
market
and
its
consumers
and
producers
is
obtained
from
a
partial
equilibrium
model
of
the
petroleum
refining
industry.
The
social
costs
of
the
controls
include
potential
economic
costs
to
consumers
of
refined
petroleum
products,
producers
of
refined
petroleum
products,
and
society
as
a
whole.

Economic
costs
are
a
better
measure
of
the
costs
of
the
air
emission
control
alternative
to
society
because
these
costs
represent
the
true
costs
or
opportunity
costs
to
society
of
resources
used
for
emission
control.

Quantifications
of
the
compliance
costs
and
economic
costs
of
the
air
emission
alternatives
are
subject
to
the
limitations
noted
in
Section
6.4
Limitations
of
the
Economic
Model.
The
social
costs
of
Alternative
2
represents
the
social
costs
of
Alternative
1
plus
the
incremental
increase
in
compliance
costs
for
Alternative
196
2.
Social
costs
were
not
estimated
independently
for
Alternative
2
due
to
limitations
in
resources.
Table
9­

1
depicts
a
comparison
of
the
benefits
of
the
alternative
proposals
to
the
compliance
and
social
costs.
A
comparison
of
the
net
benefits
for
the
alternatives
and
the
incremental
difference
in
net
benefits
between
the
alternatives
provides
an
economic
basis
for
rational
environmental
policymaking.

The
benefits
exceed
costs
(
both
compliance
and
social)
for
each
of
the
alternatives.
Thus,
either
alternative
is
viable
and
warrants
consideration.
However,
a
comparison
of
the
incremental
difference
in
the
two
alternatives
indicates
that
the
incremental
net
benefits
are
negative
for
Alternative
2.
Thus,

Alternative
1
provides
the
greatest
net
benefits
to
society.
197
TABLE
9­
1.
COMPARISON
OF
ANNUAL
BENEFITS
TO
COSTS
FOR
THE
NATIONAL
PETROLEUM
REFINING
INDUSTRY
REGULATION
(
MILLIONS
OF
1992
DOLLARS
PER
YEAR)

Alternative
1
Alternative
2
Incremental
Difference1
Benefits
$
148.3
$
153.9
$
5.6
Social
Costs
$(
132.4)
$(
148.4)
2
$(
16.0)

Benefits
Less
Social
Costs
$
16.0
$
5.5
$(
10.4)

NOTES:
(
)
represent
costs
or
negative
values.

1The
incremental
difference
represents
the
difference
between
Alternative
1
and
Alternative
2.

2Social
costs
for
Alternative
2
are
calculated
by
adding
incremental
compliance
costs
to
social
costs
of
Alternative
1.
198
