SPCC­
7­
3­
7
OPA­
1997­
0002­
0070
RESPONSE
TO
COMMENTS
DOCUMENT
FOR
THE
1991
SPILL
PREVENTION,
CONTROL,
AND
COUNTERMEASURE
(SPCC)
RULEMAKING
U.
S.
Environmental
Protection
Agency
i
TABLE
OF
CONTENTS
Response
to
Comments
Document
for
the
1991
Spill
Prevention,
Control,
and
Countermeasure
(SPCC)
Rulemaking
Page
Introduction
..........................................................
1
I:
Phase
Oneandits
relationship
to
Phase
Two..........................
3
A:
Coordination
with
other
agencies
..............................
4
B:
Worst
case
scenario
........................................
4
C:
Changing
should
to
shall
.....................................
5
D:
Ashland
oil
spill
should
not
be
the
basis
for
changes
to
the
SPCC
rule
.
7
II:
Proposed
Notification
requirements
­
§112.1(
e)
........................
9
A:
General
comments
.........................................
9
B:
Contentofnotification
form..................................
18
III:
Discretionary
provisions
.........................................
21
A:
Stating
the
design
capabilities
of
drainage
systems
..............
21
B:
Different
requirements
for
large
and
small
facilities
...............
22
IV.
General
applicability
and
notification
................................
27
A:
Scope
of
the
rule
­
"Harmful
quantities"
­
§112.1(
a),
(b),
(c)
and
(d)(
1)
27
B:
Exemption
of
completely
buried
containers
­
§112.1(
d)(
2)(
i)
and
(d)(
4)
32
C:
Exemption
of
permanently
closed
containers
­
§112.1(
b)(
2)
and
(d)(
2)
38
D:
Exemption
of
Minerals
Management
Service
(MMS)
facilities

112.
1(
d)(
3)..............................................
40
E:
Regulatory
threshold
­
§112.1(
d)(
2)
..........................
42
F:
WastewaterTreatment­§
112.
1(
d)(
6)
..........................
60
V:
Definitions­§
112.
2
.............................................
63
VI:
Preparingandimplementing
Plans
.................................
94
A:
Time
frames
for
preparing
and
implementing
Plans­§
112.
3(
a),(
b),(
c)
....................................
94
B:
Good
engineering
practice
­
§112.3(
d)
........................
100
C:
PE
certification
requirement
­
§112.3(
d)
.......................
102
D:
Whether
the
certifying
PE
may
be
a
facility
employee
or
have
any
direct
financial
tie
to
the
facility
­
§112.
3(
d)
any
direct
financial
tie
to
the
facility
­
§112.
3(
d)
...................................
109
E:
PEs­
Stateregistration­§
112.
3(
d)
­§
112.
3(
d)
.................
112
F:
PEs­
Site
visits
­§
112.
3(
d).................................
113
TABLE
OF
CONTENTS
(continued)
Page
ii
G:
PE
Plan
certification
­
completion
of
testing
procedures
­
§112.3(
d)
.
117
H:
Plan
location
at
the
facility
­
§112.
3(
e)
........................
118
I.
Extension
of
time
­§
112.
3(
f)
...............................
120
VII:
Amendment
to
a
Plan
by
the
RA
..................................
121
A:
Registered
agents
­
§112.4(
a)
and
(e)
........................
121
B:
Discharge
reports
to
EPA
­
§112.4(
a)
.........................
123
C:
General/
other
­
§112.4
....................................
125
VIII:
Amendment
to
a
Plan
by
the
owner
or
operator
......................
130
A:
Plan
amendment
by
an
owner
or
operator
­
§112.5(
a)
............
130
B:
Periodic
reviewof
plans­§
112.
5(
b)
..........................
137
C:
PE
certification
of
technical
amendments
­
§112.5(
c)
.............
139
IX:
Penalties
­
§112.6
.............................................
142
X:
General
substantive
requirements
­
§112.7
.........................
143
A:
Reorganization
of
the
regulation
­
§112.7(
a)
and
(a)(
1)
...........
143
B:
Deviations­§
112.
7(
a)(
2)
..................................
145
C:
Planinformation
­§
112.
7(
a)
and(
b)
..........................
148
D:
Secondary
containment
­
§112.7(
c)
.........................
167
E:
Contingency
planning
­
§112.7(
d)
............................
176
F:
Integrity
andleaktesting
­§
112.
7(
d)..........................
186
G:
Inspections,
tests,
andrecords
­§
112.
7(
e).....................
197
H:
Training­§
112.
7(
f)
.......................................
200
I:
Security
(excluding
production
facilities)
­
§112.
7(
g)
.............
204
J:
Facility
tank
car
and
tank
truck
loading/
unloading
racks
­
§112.7(
h)
.
208
K:
State
rules­§
112.
7(
j)
.....................................
213
XI:
Onshore
facility
Plan
requirements
(excluding
production
facilities)
.......
217
A:
Facility
Drainage
­
§112.8(
b)
................................
217
B:
Bulkstoragecontainers
­§
112.
8(
c)
..........................
221
C:
Facility
transfer
operations,
pumping,
and
facility
process
­
§112.
8(
d)
250
XII:
Onshore
production
facility
Plan
requirements
.......................
267
A:
Production
facilities
­
general
requirements
­
§112.9(
a)
...........
267
B:
:
Facility
drainage
­
§112.9(
b)
................................
268
C:
FEMA
requirements
­
proposed
§112.9(
c)(
3)
...................
272
D:
Production
facilities
­
bulk
storage
containers
­
§112.
9(
c)
........
272
E:
Facility
transfer
operations
­
§112.9(
d)
(proposed
as
§112.9(
e))
....
277
XIII:
Requirements
for
onshore
drilling/
workover
facilities
­
§112.
10
.............................................
282
TABLE
OF
CONTENTS
(continued)
Page
iii
XIV:
Requirements
for
offshore
oil
drilling,
production,
or
workover
facilities
­
§112.
11
.............................................
285
XV:
Relationship
to
otherprograms
of
therule...........................
290
A:
UST­
part112...........................................
290
B:
State
programs,
SARA
Title
III,
wellhead
protection,
flood­
related
requirements,
OSHA,
and
industry
standards
­
part
112
...........
290
XVI:
Economic
analysis
.............................................
295
A:
Estimated
universe
of
regulated
facilities
......................
295
B:
Impacts
on
smallbusinesses
...............................
296
C:
Use
of
incorrectdata......................................
298
D:
Miscalculation
of
costs
....................................
299
E:
Additional
costs
..........................................
303
F:
Costs
to
the
electric
utility
industry
...........................
306
G:
Miscellaneous
cost
issues
.................................
308
H:
Miscalculation
of
benefits
..................................
312
XVII:
General
comments
............................................
314
1
INTRODUCTION
Purpose
of
this
Document
The
purpose
of
this
document
is
to
respond
to
comments
received
on
the
proposed
rule
(56
FR
54612,
October
22,
1991)
to
revise
the
Oil
Pollution
Prevention
regulation
(40
CFR
part
112),
promulgated
under
the
Clean
Water
Act
(CWA).
This
proposed
rule
establishes
requirements
for
Spill
Prevention,
Control,
and
Countermeasure
(SPCC)
Plans
to
prevent
spills
of
oil
by
non­
transportation­
related
onshore
and
offshore
facilities
into
the
navigable
waters
of
the
United
States,
adjoining
shorelines,
and
other
areas
specified
in
the
CWA.
The
proposed
revisions
involve
changes
in
the
applicability
of
the
regulation,
changes
to
the
required
procedures
for
completing
SPCC
Plans,
and
a
new
facility
notification
provision.

Background
of
this
Rulemaking
The
Oil
Pollution
Prevention
regulation,
or
SPCC
regulation,
was
originally
promulgated
on
December
11,
1973
(38
FR
34164),
under
the
authority
of
section
311(
j)(
1)(
C)
of
the
CWA.
The
regulation
established
spill
prevention
procedures,
methods,
and
equipment
requirements
for
non­
transportation­
related
facilities
with
aboveground
oil
storage
capacity
greater
than
1,320
gallons
(or
greater
than
660
gallons
aboveground
in
a
single
tank);
or
buried
underground
oil
storage
capacity
greater
than
42,000
gallons.
Regulated
facilities
were
those
that,
because
of
their
location,
could
reasonably
be
expected
to
discharge
oil
into
the
navigable
waters
of
the
United
States
or
adjoining
shorelines.

We
have
amended
the
SPCC
requirements
a
number
of
times,
and
those
amendments
are
described
in
an
October
22,
1991
Federal
Register
notice.
56
FR
54612.
In
the
October
1991
notice,
in
addition
to
the
description
of
past
amendments,
EPA
proposed
new
revisions
that
involved
changes
in
the
applicability
of
the
regulation
and
the
required
procedures
for
the
completion
of
SPCC
Plans,
as
well
as
the
addition
of
a
facility
notification
provision.
The
proposed
rule
also
reflected
changes
in
the
jurisdiction
of
section
311
of
the
Act
made
by
amendments
to
the
Act
in
1977
and
1978.
We
have
finalized
some
of
those
proposed
revisions,
with
modifications,
in
this
rule.

Organization
of
the
Comment
Response
Document
To
develop
this
document,
we
first
reviewed
the
letters
received
in
the
public
docket.
We
then
identified
relevant
issues
raised
by
the
commenters
based
on
the
content
of
the
proposed
rule.
Finally,
we
developed
responses
to
these
summaries,
carefully
addressing
the
issues
in
each
issue
category.
The
following
pages
present
the
comments
and
responses.

We
arranged
the
document
according
to
the
subjects
listed
in
the
Table
of
Contents.
We
assigned
a
reference
number
to
each
letter
we
received.
We
include
reference
numbers
in
the
summaries
to
identify
the
commenters
who
addressed
each
issues.
For
2
letters
that
addressed
numerous
issues,
the
corresponding
letter
number
will
appear
multiple
times
throughout
the
document.

In
this
comment
response
document,
the
"current
rule"
means
part
112
as
codified
in
the
most
recent
edition
of
the
Code
of
Federal
Regulations,
as
amended
by
any
subsequent
part
112
final
rule
published
in
the
Federal
Register
since
that
codification
and
preceding
the
publication
of
this
final
rule.
3
Category
I:
Phase
One
and
its
relationship
to
Phase
Two
Background:
In
the
wake
of
the
1988
Ashland
Oil
Spill
in
Floreffe,
Pennsylvania,
we
formed
the
Oil
Spill
Prevention,
Control,
and
Countermeasure
(SPCC)
Program
Task
Force
(the
Task
Force)
to
examine
Federal
regulations
addressing
oil
spills
from
aboveground
storage
tanks
(ASTs).
This
Task
Force
recommended
that
we
distinguish
guidance
from
required
provisions,
establish
more
technical
requirements
for
all
facilities
subject
to
the
oil
spill
prevention
program,
and
require
facility­
specific
oil
spill
contingency
planning.
Further,
having
found
that
we
lacked
an
adequate
inventory
of
regulated
facilities,
the
Task
Force
recommended
that
we
collect
information
on
regulated
facilities
(for
example,
the
number
of
ASTs
at
a
facility.
Finally,
the
Task
Force
recommended
that
we
strengthen
our
facility
inspection
program
better
to
identify
violations
and
encourage
compliance.
A
subsequent
General
Accounting
Office
(GAO)
report
contained
similar
recommendations.

As
we
explained
in
the
1991
Preamble,
we
decided
to
address
the
Task
Force
and
GAO
recommendations
in
two
phases.
In
Phase
One,
we
addressed
those
oil
program
provisions
we
could
change
without
performing
substantial,
additional
data
gathering.
As
an
element
of
Phase
One,
we
proposed
to
require
elementary
contingency
planning
of
a
kind
already
in
most
SPCC
Plans.
In
Phase
Two,
we
implemented
new
mandates
arising
under
the
Oil
Pollution
Act
of
1990
(OPA),
including
requiring
substantial
contingency
(or
response)
planning.
In
1991,
we
also
requested
comments
on
the
relationship
between
Phase
One
and
Phase
Two.
We
issued
the
Phase
Two
or
facility
response
plan
(FRP)
rules
in
1994.
59
FR
34070,
July
1,
1994,
codified
at
40
CFR
112.20
and
112.21.

Comments:
Timing
of
Phases.
"This
second
phase
should
be
expedited
to
provide
the
increase
prevention
and
containment
that
will
result
from
improved
SPCC
plans."
(L1)
We
should
avoid
timing
constraints
that
would
require
regulated
owners
and
operators
to
produce
a
Phase
One
plan,
a
Phase
Two
plan,
and
perhaps,
a
third
plan
to
meet
state­
specific
requirements.
(67,
79,
91,
L10)
The
requirement
for
contingency
plans
should
be
phased
in,
allowing
each
facility
to
delay
actual
preparation
until
the
next
statutorily­
mandated
SPCC
Certification.
(L20)

Facility
Notification.

Premature.
Notes
that
OPA
responsibilities
have
not
yet
been
delegated
to
EPA.
"Until
such
a
delegation
is
made,
the
Agency
cannot
determine
what
its
responsibilities
will
be.
At
this
time,
it
is
simply
unreasonable
for
the
Agency
to
burden
the
regulated
community
with
a
notification
process
which
is
not
necessary."
(42,
91,
141,
167,
182)
"Until
EPA
has
outlined
its
data
needs
and
how
the
information
will
be
used
under
Phase
Two,
expanding
the
notification
requirements
at
this
time
is
unwarranted,
unjustified
and
unnecessarily
costly."
(167)
4
Timely.
"Requiring
this
additional
information
during
Phase
I
(instead
of
deferring
to
Phase
II),
will
enable
the
Regions
to
have
more
time
to
develop
a
matrix
for
determination
of
facilities
posing
significant
harm/
significant
and
substantial
harm.
Of
all
the
information
requested
on
the
notification
form,
the
additional
information
listed
above
is
most
likely
to
be
confusing
to
the
regulated
community,
and
hence
the
Regions
should
be
afforded
as
much
lead
time
as
possible
to
clarify
and
troubleshoot
the
screening
data
submitted."
(168)

Public
hearings.
"In
addition,
since
EPA
offers
these
proposed
rules
based
only
on
the
views
of
a
governmental
task
force
with
no
representation
of
the
regulated
community,
and
since
EPA's
rules
seek
to
impose
burdens
on
the
regulated
community
as
a
class
based
on
one
large,
unfortunate
bulk
storage
incident,
Cyprus
respectfully
requests
that
appropriate
public
hearings
be
held."
(35)

Response:
Timing
of
Phases.
We
appreciate
the
comment
that
supported
our
early
efforts
to
collect
information
on
SPCC­
covered
facilities.
However,
because
the
OPA­
mandated
deadlines
made
it
necessary
for
us
to
concentrate
our
efforts
on
promulgating
the
Phase
Two
rule;
we
issued
a
Phase
Two
proposed
rule
in
1993
(58
FR
8824,
February
17,
1993),
and
a
Phase
Two
final
rule
in
1994
(59
FR
34070,
July
1,
1994).

Facility
Notification.
We
have
decided
to
withdraw
the
proposed
facility
notification
requirement
because
we
are
still
considering
issues
associated
with
establishing
a
paper
versus
electronic
notification
system,
including
issues
related
to
providing
electronic
signatures
on
the
notification.
Should
the
Agency
in
the
future
decide
to
move
forward
with
a
facility
notification
requirement,
we
will
repropose
such
requirement.

Public
hearings.
Public
hearings
on
the
rule
were
unnecessary
due
to
the
extensive
written
response
we
received,
elucidating
all
sides
of
most
issues.

I­
A
Coordination
with
other
agencies
Comments:
Asks
us
to
coordinate
the
Phase
Two
rulemaking
with
other
Federal
and
State
regulatory
activities,
reasoning
that
government
entities
should
avoid
creating
conflicting
requirements
and
duplicating
efforts.
One
State
noted
that
it
had
received
many
comments
on
its
requirements.
(102,
193,
193,
L10).

Response:
We
did
coordinate
the
Phase
Two
rulemaking
with
other
agencies.
See
the
preambles
to
the
1993
proposed
rule
and
1994
final
rule,
and
1994
Response
to
Comment
document
for
details.

I­
B
Worst
case
scenario
Comments:
Worst
case
planning.
"ACMS
believes
that
facilities
with
adequate
secondary
containment
should
not
be
required
to
install
leak
detection
monitors
or
5
prepare
and
submit
a
plan
for
responding
to
the
largest
foreseeable
discharge."
(51)
"Our
experience
in
assisting
facilities
after
a
spill
has
shown
that
many
of
them
anticipated
­
and
planned
for
­
a
spill
of
far
less
serious
magnitude
than
the
one
that
actually
occurred.
Accordingly,
3M
believes
the
SPCC
regulation
should
expressly
require
the
calculation
of
a
worse
case
scenario
as
part
of
each
contingency
plan."
(61)
Equipment.
"3M
believes
the
SPCC
regulation
should
require
each
contingency
plan
to
document
the
availability
of
enough
sorbent
material
and
other
equipment
to
manage
a
worst­
case
spill."
(61)

Response:
Worst
case
planning.
We
agree
that
an
SPCC
facility
should
not
have
to
plan
for
the
worst
case
scenario.
Contingency
planning
following
the
provisions
of
part
109
requires
planning
for
"varying
degrees
of
response
effort
depending
on
the
severity
of
the
oil
discharge."
40
CFR
109.5(
d)(
4).
We
require
worst
case
scenario
planning
for
higher
risk
FRP
facilities.
We
addressed
comments
and
issues
concerning
a
worst
case
discharge
in
our
FRP
rulemaking.

Equipment.
Part
109
requires
provisions
that
include
the
"identification
and
inventory
of
applicable
equipment,
materials
and
supplies
which
are
available
locally
and
regionally,"
and
"an
estimate
of
the
equipment,
materials
and
supplies
which
would
be
required
to
remove
the
maximum
oil
discharge
to
be
anticipated."
40
CFR
109.5(
c)(
1)

2).

I­
C:
Changing
should
to
shall
Issues:
In
§112.7
of
the
current
rule,
we
set
general
guidelines
for
the
preparation
and
implementation
of
a
Plan.
In
the
1991
proposal,
we
substituted
the
words
requirements
and
shall
for
the
words
guidelines
and
should.

Comments:
Support
for
proposal.
"All
the
major
federal
reports
following
the
Ashland
Oil
spill
recommended
that
SPCC
requirements
be
more
specific
so
they
could
be
better
enforced.
Commendably,
EPA
has
in
several
places
in
the
SPCC
proposal
put
in
mandatory
language.
In
several
other
places,
however,
EDF
urges
EPA
to
use
language
that
would
make
certain
provisions
mandatory,
rather
than
retaining
flexibility
which
may
result
in
adverse
impacts
on
the
environment."
(27,
44,
53,
67,
148,
185,
L17)

Opposition
to
proposal.
"API
also
suggests
that
the
proposed
new
requirements
as
discussed
in
this
rule
remain
as
recommendations
only
for
such
facilities
designated
as
`small'
according
to
this
definition
and/
or
that
all
the
newly
proposed
`shalls'
(as
in
the
current
SPCC
regulation)
for
all
such
`small
facilities'."
(67)
The
existing
guidelines
should
be
relaxed
if
we
change
should
to
shall.
(101)
Stresses
the
need
for
"practical
flexibility."
Our
original
intent
was
to
use
should
to
provide
a
flexibility
that
would
end
with
the
change
to
shall.
(110,
L27,
L27)
A
set
of
mandated
principles
is
inconsistent
with
good
engineering
practice.
"(
G)
ood
engineering
practice
begins
with
the
base
requirements
and
develops
the
most
practicable
solution."
(45,
170)
6
Guidance
documents.
"...(
D)
iscretionary
provisions
might
be
better
set
forth
in
a
separate
guidance
document,
so
as
not
to
confuse
the
regulated
community."
(27)

Substantive
change.
The
change
is
not
merely
a
clarification
in
rule
language.
The
proposal
is
a
substantive
change
for
which
we
failed
to
give
proper
notice.
The
change
from
should
to
shall
would
impose
a
new
regulatory
burden
on
an
owner
or
operator
by
requiring
that
he
modify
an
existing
SPCC
Plan
and
facility.
It
would
be
"inappropriate
for
the
EPA
to
issue
a
final
rule
until
fair
public
notice
and
opportunity
for
comment
has
been
given."
(32,
35,
63,
127,
L27)

New
costs
or
burdens.
The
change
would
substantially
increase
costs
for
production
facilities.
(28,
101,
110,
125,
146,
189,
L27)
This
increase
in
costs
would
be
enough
to
shut
down
some
facilities.
(28,
110)
We
have
no
substantive
basis
to
justify
making
the
current
provisions
mandatory.
(101,
125,
189)
It
is
more
cost
effective
for
the
facility
owner
or
operator
to
retain
discretion
in
selecting
the
exact
requirements
necessary
for
the
specific
facility
location.
(125,
173)
We
have
underestimated
the
costs
of
the
changes.
(125,
L27)

Small
facilities.
Recommends
that
shall
remain
should
for
small
facilities.
(91,
116,
133,
173,
182)
New
requirements
"should
not
apply
to
production
facilities
with
tanks
of
1,000
barrels
(42,000
gallons)
or
less."
(91)
We
should
allow
the
owner
or
operator
of
a
small
or
medium
size
facility
more
discretion
than
owners
or
operators
of
"large
bulk
oil
storage
facilities
with
over
42,
000
gallons
of
capacity."
(116)
We
should
limit
analysis
requirements
to
"tanks
larger
than
660
gallons
and
electrical
equipment
larger
than
10,000
gallons
because
it
is
impractical
and
unnecessary
to
do
such
analyses
for
all
smaller
units."
(125)
"The
`should's'
to
`shalls'
change
should
not
apply
to
small
production
facilities...
with
less
than
3,
000
barrels
of
oil
storage
capacity."
(133)
We
should
exempt
facilities
with
less
than
1,
000
barrels
of
oil
storage
capacity.
(173)

Response:
Support
for
proposal.
We
appreciate
commenter
support
of
the
change
from
should
to
shall.
We
believe
that
we
must
retain
flexibility
for
a
deviation
when
an
owner
or
operator
faces
unique
circumstances.
No
single
design
or
operational
standard
can
be
prescribed
for
all
non­
transportation­
related
facilities.

Substantive
change.
We
disagree
that
the
change
is
either
substantive
or
contrary
to
legislative
intent.
Section
311(
j)(
1)(
C)
of
the
Act
authorizes
the
President
and,
through
delegation,
EPA,
to
establish
"procedures,
methods,
and
equipment
and
other
requirements
for
equipment
to
prevent
discharges
of
oil
and
hazardous
substances
from
vessels
and
from
onshore
facilities
and
offshore
facilities,
and
to
contain
such
discharges."
That
authority
is
ample
to
provide
the
basis
for
a
mandatory
SPCC
rule,
that
is,
a
rule
that
establishes
"requirements
...
to
prevent
discharges."
We
also
disagree
that
the
proposed
rule
failed
to
provide
proper
notice
and
comment.
The
preamble
to
the
1991
proposed
rule
fully
explained
the
rationale
for
the
proposed
change
(56
FR
54620,
October
22,
1991),
and
numerous
commenters
responded.
Furthermore,
we
have
always
interpreted
and
enforced
our
rules
as
mandatory
requirements.
7
EPA
recognizes,
however,
that
this
clarification
may
result
in
certain
owners
or
operators
of
regulated
facilities
recognizing
for
the
first
time
that
they
have
been
and
are
subject
to
various
provisions
of
part
112.
Such
owners
and
operators
should,
of
course,
take
all
necessary
steps
to
come
into
compliance
with
this
part
as
soon
as
possible.
If
an
owner
or
operator
reports
to
EPA
that
he
is
out
of
compliance
with
part
112,
he
may
qualify
for
a
significantly
lesser
penalty
under
EPA's
policy
entitled
"Incentives
for
Self­
Policing:
Discovery,
Disclosure,
Correction
and
Prevention
of
Violations"
that
was
published
at
60
FR
66706,
on
December
22,
1995.
Furthermore,
in
exercising
its
prosecutorial
discretion,
the
Agency
always
takes
into
account
the
good
faith
and
efforts
to
comply
of
an
owner
or
operator
who
has
been
in
noncompliance
with
applicable
laws
and
regulations.

Good
engineering
practice.
We
disagree
that
mandatory
requirements
are
inconsistent
with
good
engineering
practice.
We
continue
to
allow
deviations
from
most
substantive
rule
requirements,
based
on
good
engineering
practice
(§
112.7(
a)(
2))
or
impracticability
(§
112.
7(
d)).

New
costs
or
burdens.
We
disagree
that
this
editorial
change
imposes
any
new
regulatory
burdens
or
costs
because
it
imposes
no
new
requirements.
Nor
will
the
clarifying
change
add
to
the
information
collection
burden
–
it
remains
the
same.

Small
facilities.
We
disagree
that
the
should
to
must
change
will
impose
new
requirements
or
costs
for
small
facilities.
We
have
modified
the
applicability
thresholds
in
the
rule
so
that
many
small
facilities
are
no
longer
covered.
In
addition,
we
have
included
general
deviation
provisions
in
§112.7(
a)(
2)
and
(d).

I­
D
Ashland
oil
spill
should
not
be
the
basis
for
changes
to
the
SPCC
rule
Comments:
Ashland
spill.
"The
thickness
of
the
Ashland
lower
chime
was
more
than
1
inch.
On
the
other
hand,
oil
and
gas
field
tanks,
are
fabricated
from
10
gauge
steel
(0.10
inches
thick).
Steel
of
this
thinness
is
not
impact
or
thermal
stress
sensitive
because
of
ease
of
rolling
thin
steel
plates.
Accordingly,
an
Ashland
type
spill
is
extremely
likely
to
occur
in
oil
and
gas
operations.
Additionally,
EPA,
in
the
preamble,
cites
does
not
data
demonstrating
such
spills
or
releases
are
liable
to
occur
in
E&
P
operations."
(31,
34,
110,
114).

Actual
risk,
major
spills.
In
proposing
changes
to
part
112,
we
should
assess
actual
situations
that
threaten
public
health
and
the
environment.
(52,
139)
We
should
have
different
SPCC
Plan
requirements
for
facilities
based
on
different
risks
to
human
health
and
the
environment.
(86)
We
should
make
part
112
address
the
prevention
of
potential
major
oil
spills
only,
adding
that
significant
changes
in
the
SPCC
rule
would
not
"improve
containment
facilities
insofar
as
Appalachian
Producers
are
concerned."
(101)
Supports
clarification
that
"SPCC
plans
are
required
(not
voluntary)
of
facilities
which
pose
a
certain
potential
harm
to
navigable
waters
if
oil
is
released
from
storage
tanks."
(164)
8
Small
facilities,
exploration
and
production
facilities.
Regulations
promulgated
as
a
result
of
the
Ashland
oil
spill
should
not
apply
to
small
aboveground
tanks.
(28,
69,
79,
101,
110)
The
proposed
regulation
unduly
burdens
small
facilities,
borderline
sized
facilities,
facilities
distant
from
waterways,
or
facilities
in
rural
areas
with
construction
and
equipment
standards
that
apply
to
Ashland­
type
facilities.
(32,
72)
We
developed
the
proposed
changes
to
prevent
large
Ashland­
type
spills.
The
proposed
changes
are
not
applicable
to
oil
and
gas
operations
which
have
small
volumes
of
stored
oil
(110),
or
exploration
and
production
(E&
P)
facilities
which
are
generally
not
situated
near
major
waterways
(110,
114).

Response:
Ashland
spill.
As
noted
in
the
preamble
to
the
1991
proposed
rule,
we
reevaluated
part
112
as
a
consequence
of
findings
and
recommendations
by
the
SPCC
Task
Force
formed
in
the
aftermath
of
the
Ashland
spill,
and
of
similar
findings
in
a
GAO
report.
Although
the
Task
Force
report
focused
on
preventing
large,
catastrophic
spills;
the
report
addressed
many
aspects
of
the
Federal
oil
spill
prevention,
control,
and
countermeasure
program.
The
Task
Force
report
was
one
impetus
for
the
1991
proposed
rule,
however
the
proposed
rules
in
issue
were
meant
to
address
broader
issues
than
the
Ashland
spill
and
similar
spills.
See
56
FR
54612­
3,
October
22,
1991,
for
a
detailed
discussion
of
the
reasons
supporting
the
1991
proposal.

Actual
risk,
major
spills.
The
changes
to
the
rule
do
address
actual
situations
that
threaten
public
health
and
the
environment.
A
facility
may
have
different
SPCC
Plan
requirements
based
on
different
risks
to
human
health
and
the
environment.
We
disagree
that
the
rule
should
address
the
prevention
of
potential
major
oil
spills
only.
Small
discharges
of
oil
may
be
harmful
to
the
environment.

Small
facilities,
exploration
and
production
facilities.
We
disagree
that
small
facilities
or
oil
and
gas
E&
P
facilities
should
fall
outside
of
the
SPCC
program
structure.
Such
facilities
store
or
use
oil
and
may
be
the
source
of
a
discharge
as
described
in
§112.1(
b).
Therefore,
they
must
be
subject
to
part
112.

Potential
harm.
A
facility
posing
a
reasonable
possibility
of
a
discharge
as
described
in
§112.
1(
b),
and
meeting
other
applicability
criteria,
is
subject
to
the
rule.
9
Category
II:
Proposed
Notification
requirements
­
§112.1(
e)

II
­
A:
General
comments
Background:
In
1991,
EPA
proposed
to
require
that
any
facility
subject
to
its
jurisdiction
under
the
Clean
Water
Act
which
also
meets
the
regulatory
storage
capacity
threshold
notify
the
Agency
on
a
one­
time
basis
of
its
existence.
This
type
of
notice
is
separate
from
the
notice
required
at
40
CFR
110.3
of
a
discharge
which
may
be
harmful
to
the
public
health
or
welfare
or
the
environment.
We
did
not
propose
any
change
to
§110.3.

We
proposed
that
facility
notification
include,
among
other
items,
information
concerning
the
number,
size,
storage
capacity,
and
locations
of
ASTs.
The
proposal
would
have
exempted
from
the
notification
requirement
information
regarding
the
number
and
size
of
completely
buried
tanks,
as
defined
in
§112.2.
The
rationale
for
notification
was
that
submission
of
this
information
would
be
needed
to
help
us
identify
our
universe
of
facilities
and
to
help
us
administer
the
Oil
Pollution
Prevention
Program
by
creating
a
data
base
of
facility­
specific
information.
We
also
asked
for
comments
regarding
the
form
on
which
notification
would
be
submitted,
and
on
various
possible
items
of
information
that
could
be
included
besides
the
ones
proposed.
Lastly,
we
asked
for
comments
on
alternate
forms
of
facility
notification.
56
FR
54614­
15.

Comments:
Support
for
proposal.
There
is
generally
no
current
procedure
whereby
we
could
identify
the
universe
of
sites
subject
to
the
SPCC
rule,
and
an
inventory
of
these
facilities
is
necessary.
(27,
44,
51,
53,
62,
91,
107,
121,
135,
154,
164,
168,
181,
182,
L5,
L10,
L11)

Additional
information.

Age
of
containers.
"The
age
of
tanks
may
not
correspond
to
its
potential
to
spill.
Depending
on
the
product
stored,
thickness
of
plate,
type
of
construction,
and
any
repairs
or
reconditioning
done,
a
tank's
age
is
not
a
good
indication
of
soundness."
(51)

Adverse
weather.
"The
question
of
adverse
weather
is
subjective.
What
may
be
one
facilities
[sic]
adverse
weather
may
be
another's
normal
weather.
The
potential
should
be
identified
by
the
local
emergency
planning
committee
or
the
US
geological
service
[sic]."
(51)

Cost
of
additional
information.
Asking
for
more
information
would
increase
the
reporting
burden
and
raise
compliance
costs
to
the
tens
of
millions.
(125)

Environmentally
sensitive
areas.
"These
locations
may
be
unknown
to
the
facilities
and
should
be
identified
by
the
local
emergency
planning
committee."
(51)
We
proposed
to
require
the
owner
or
operator
to
provide
additional
information
(i.
e.,
location
of
environmentally
sensitive
areas,
potential
for
10
adverse
weather)
which
is
"completely
beyond
reason."
These
requirements
would
be
costly
and
time
consuming.
(31,
34)
Opposes
following
items
on
the
notification
form:
spill
histories,
age
of
tanks,
location
of
environmentally
sensitive
areas,
and
potential
for
adverse
weather.
(75)
A
general
request
for
information
on
environmentally
sensitive
areas
and
the
potential
for
adverse
weather
would
not
help
the
development
of
Area
Plans,
because
any
response
was
likely
to
be
speculative.
(103)

LEPCs,
other
emergency
responders.
We
should
require
an
owner
or
operator
to
submit
the
SPCC
Plan
to
the
appropriate
Local
Emergency
Planning
Committee
(LEPC).
(43)
On­
scene
Coordinators
(OSCs)
should
inform
LEPCs
of
SPCC
rule
violations.
(
L1)
We
should
encourage
facilities
and
LEPCs
to
conduct
exercises
together,
in
conjunction
with
OSCs
and
local
fire
departments.
(L1,
L11)

SERCs,
OSROs.
We
should
require
owners
or
operators
to
submit
the
proposed
notification
information
to
State
Emergency
Response
Commissions
(SERCs)
(27,
L11),
oil
spill
response
agencies
(27),
and
States
(154).
This
information
will
help
States
identify
regulated
facilities.
(L11)

Other
owners.
Notification
should
include
names
of
the
"owner
of
the
facility,
owner
of
the
improvements
at
the
facility,
and
the
owner
of
the
land
at
the
facility.
...
Perhaps
one
of
the
most
significant
landowners
in
the
country
who
is
prejudiced
by
the
absence
of
a
requirement
for
landowner
involvement
in
the
preparation
of
an
SPCC
Plan
is
the
United
States
Government.
"
(43)

PEs.
We
should
require
an
engineer
employed
by
the
owner
or
operator
to
prepare
and
sign
the
notification.
(75)

Placards.
We
should
require
an
owner
or
operator
to
display
a
placard
that
includes
ownership
information
and
a
unique
facility
identification
number.
(154)

Product
stored.
We
should
require
information
on
the
product
stored
in
each
tank
and
how
it
is
delivered
to
the
facility.
We
should
collect
tank
data
similar
to
the
data
we
collect
for
underground
storage
tanks.
(111)

SPCC
compliance.
The
notification
form
should
include:
"an
affidavit
signed
by
a
member
of
management
within
the
owner
or
operator's
management
certifying
that
the
facility's
SPCC
Plan
has
been
prepared
in
accordance
with
all
relevant
provisions
of
40
CFR
part
112
and
has
been
placed
in
effect...."
(43)

Address.
Suggests
use
of
longitude
or
latitude,
or
Universal
Transverse
Mercator
system,
or
a
mailing
address
for
a
facility
without
a
street
address.
(78,
101,
116,
121,
L11)
11
Alternatives
On­
site
surveys.
We
should
obtain
additional
information
through
statisticallyrepresentative
sampling
using
on­
site
surveys.
(L12)

Other
Federal,
State,
and
local
sources.
"If
the
Agency
needs
additional
information
for
its
database,
such
as
MSDS,
it
can
certainly
obtain
this
from
the
myriad
of
other
federal,
state,
and
local
databases
for
which
we
are
required
to
submit
information."
(161)

NRC
records.
"For
example,
records
available
at
the
National
Response
Center
and
other
published
sources
may
be
used
to
identify
areas
of
the
country
and/
or
locations
where
there
significant
use
and
releases
of
oil
exist."
(155)

SARA
duplication.

SARA
duplicative.
"I
have
never
received
one
request
for
explanation
of
any
SARA
submitted
information
from
LEPCs
or
fire
departments."
(11)
Further
that
this
type
of
information
is
readily
available
without
the
SARA
Title
III
reporting
requirements
(e.
g.,
through
exploration
or
production
facilities).
"Similar
information
required
by
the
proposed
notification
is
already
reported
under
other
programs,
such
as
SARA."
(27)
"Notification
requirements
have
essentially
been
fulfilled
by
the
SARA
Title
III
regulations."
(28)
The
proposed
rule
is
duplicative
of
SARA
Title
III
regulations.
(101)
We
should
exempt
owners
or
operators
reporting
through
SARA
Title
III
from
any
part
112
notification
requirements.
(113)
Asks
us
to
consider
modifying
the
SARA
Title
III
reporting
requirements
to
satisfy
our
need
for
additional
notification
information.
(118)
Recommends
that
we
permit
using
the
Tier
II
form
or
proposed
Appendix
B
to
meet
the
proposed
SPCC
one­
time
notification
requirement.
(145)
Opposes
the
notification
requirement
because
we
already
have
the
requested
information
in
the
forms
of
SARA
311
and
312
reports.
(187)
SPCC­
covered
facilities
pose
a
hazard
equivalent
to
the
hazard
at
a
facility
with
a
threshold
amount
of
an
extremely
hazardous
substance
(EHS).
(L1)

SARA
not
duplicative.
States
presently
are
preparing
and
maintaining
data
bases
that
the
public
does
not
use
or
want.
With
the
exception
of
Local
Emergency
Planning
Committees
(LEPC)
in
large
cities,
no
one
uses
the
SARA
Title
III
data.
(110)
SARA
section
311/
312
submissions
were
intended
for
the
public
and
not
to
notify
the
Federal
government
of
environmental
threats
posed
by
oil
storage
facilities.
(168)

SARA
and
313.
Recommends
that
if
we
decided
against
accepting
the
SARA
Title
III
form
in
lieu
of
the
proposed
notification
form,
we
should
let
12
owners
or
operators
submit
the
SPCC
and
section
313
reports
at
the
same
ti
me.
(71)

State
regulatory
agencies
or
industry
trade
association
surveys.
(31,
42,
L17)

Threshold
for
notification.

42,000
gallons.
We
are
creating
an
unnecessary
burden
for
ourselves
and
industry
by
requiring
notification
from
all
SPCC
facilities.
We
should
require
notice
only
for
facilities
with
more
than
42,
000
gallons
of
bulk
storage
capacity.
We
should
require
notice
for
small
and
medium
size
facilities
only
if
there
has
been
an
oil
spill
from
the
facility
within
the
preceding
three
years.
(114,
116)

100,000
gallons.
(136)

Applicability.

Discharge
history.
We
failed
to
explain
in
the
notification
form
that
part
112
does
not
cover
a
facility
unless
it
is
reasonably
likely
to
discharge
oil
into
U.
S.
navigable
waters
(and
meets
the
other
SPCC
program
criteria).
We
should
address
the
connection
between
part
112
applicability
and
the
likelihood
that
a
facility
may
discharge
oil
into
navigable
waters.
(48)
The
notification
provisions
apply
to
facilities
that
"may"
discharge
harmful
quantities
into
navigable
waters.
In
the
rule,
we
should
clarify
how
we
intend
to
determine
which
facilities
"may"
discharge
harmful
quantities
and
who
will
make
this
determination.
(111)
We
should
regulate
facilities
that
have
had
spills,
rather
than
those
that
have
not
had
spills.
(132)

SPCC
facilities.
We
should
require
notice
for
any
facility
for
which
an
SPCC
Plan
is
required.
(43)
We
should
require
the
notification
form
only
for
a
part
112
facility.
(149)

"Unacceptable
risk."
Asks
us
to
decide
what
constitutes
"unacceptable
risk,"
rather
than
requiring
an
owner
or
operator
to
register
all
aboveground
tanks.
We
should
use
a
given
facility's
reported
spill
history
as
a
prioricriterion
for
determining
which
tanks
the
owner
or
operator
must
register.
(132)

Dun
&
Bradstreet
numbers.
Exploration
and
production
facilities
rarely
have
Dun
&
Bradstreet
numbers.
(42,
58,
L12)

Enforcement.
To
ensure
notification,
many
States
penalize
those
who
deliver
regulated
substances
to
non­
compliant
UST
facilities.
(76)
We
should
consider
focusing
upon
non­
reporting
owners
or
operators
rather
than
imposing
an
additional
burden
on
industries
already
heavily­
regulated.
(162)
13
Facility
diagrams.
Section
112.1(
d)
should
be
rewritten
because
it
seems
to
require
otherwise
exempt
facilities
to
comply
with
facility
notification
requirements,
such
as
providing
facility
diagrams.
(133)

Format.
Owners
or
operators
will
copy
the
notification
form
from
the
Federal
Register,
and
will
not
submit
it
as
a
one­
page,
double­
sided
form.
(27)
Suggests
the
following:
"(
P)
lease
return
the
notification
form
to
EPA
unfolded
in
a
9­
inch
by
12­
inch
envelope."
(48)
We
should
permit
submitting
a
computer­
generated
copy
of
any
final
notification
form
and
provide
for
electronic
data
submission.
(101)
EPA
and
USCG
should
use
the
same
form.
(171)

Hazardous
chemicals.
We
should
revise
our
discussion
of
petroleum
products
in
the
Preamble,
because
crude
oil
is
not
a
"hazardous
chemical,"
nor
is
it
subject
to
SARA
Title
III
reporting
requirements.
(34)

Information
collection
burden.
We
underestimated
the
burden
of
completing
and
submitting
the
notification
form.
(31,
34,
35,
48,
86,
187,
192)
If
we
require
more
information,
we
would
increase
the
reporting
and
record
keeping
burden
on
industry.
(79,
125,
164)
Compiling
more
information,
in
turn,
would
mean
increasing
the
time
for
submitting
the
notification
form.
(34,
95,
102,
168,
191,
L7)

Navigable
waters.
There
is
no
definition
of
navigable
waters
on
the
form,
making
it
difficult
to
answer
questions
concerning
them.
(31,
41
48,
58,
62,
67,
79,
85,
86,
107,
146,
160,
L17)

Unreasonable
distance.
"The
categories
for
reporting
distance
to
navigable
waters
exceed
reasonable
distances.
Facilities
`more
than
10
miles'
from
navigable
waters
will
rarely,
if
ever,
reasonably
be
expected
to
discharge
oil
in
quantities
that
may
be
harmful,
into
or
upon
the
navigable
waters
of
the
United
States.
This
is
also
probably
true
beginning
at
category
4–`½
miles'."
(42)
We
should
specify
a
minimum
distance
to
navigable
waters,
on
the
theory
that
only
facilities
within
a
certain
distance
would
have
a
reasonable
possibility
of
discharge
to
such
waters.
(42,
125)

Opposition
to
proposal.

Differing
facilities.
We
should
issue
another
proposal
with
different
requirements
for
different
kinds
of
facilities.
(31,
86)

Exploration
and
production
facilities.
Drilling
rigs
move
from
location
to
location
as
often
as
every
few
months.
(67,
85,
91)

Duplicative
requirement.
It
is
unnecessary,
because
the
information
sought
might
be
better
obtained
from
other
sources,
e.
g.:
State
sources
(101,
111,
113,
165,
166,
188,
L15);
SARA
Title
III
reports
(
58,
70,
71,
89,
101,
113,
114,
145,
162,
165,
169,
187,
188,
192,
L12,
L15);
NPDES
permits
(56,
145);
underground
14
storage
tank
regulations
(149);
emission
inventory
programs
(25);
industry
trade
association
surveys
(31,
160,
and
161);
fire
regulatory
authorities
(65);
DOT's
maps
and
records
rulemaking
(L30);
and
the
Minerals
Management
Service
(133).
Proposal
includes
duplicative
reporting
requirements.
(131)

Electric
utilities.
Because
hundreds
of
thousands
of
utility
facilities
will
be
required
to
submit
notification
forms,
our
proposal
would
impose
a
substantial
burden
on
electric
utilities.
Our
proposed
reporting
requirement
would
cost
the
utility
industry
several
million
dollars.
(125)

Format.
The
notification
form
does
not
provide
the
information
that
the
EPA
Task
Force
report
recommends
we
collect,
nor
is
its
collection
of
AST
information
as
comprehensive
as
the
form
used
for
underground
storage
tank
(UST)
notification
under
Appendix
I
of
40
CFR
part
280.
(44)
Section
112.1(
e)(
2)
should
read:
"The
written
notice
shall
be
provided
either
by
submitting
a
copy
of
the
facility's
312
report
or
by
using
the
EPA
form."
(71)

Inventory,
not
capacity.
Opposes
using
the
information
obtained
through
the
SARA
Title
III
notification
requirement
as
a
substitute
for
the
SPCC
one­
time
notification
requirement
because
the
SARA
Title
III
program
measures
inventory,
not
capacity.
Some
tanks
may
not
be
in
use,
may
not
be
filled
to
capacity,
or
may
store
a
non­
oil
product.
Therefore,
we
would
not
receive
a
correct
estimate
of
potential
discharge
from
SARA
Title
III
submissions.
To
reduce
the
paperwork
burden,
we
should
explore
alternative
filing
methods,
including
accepting
the
SARA
Title
III
form
instead
of
the
proposed
Appendix
B
notification
form.
(51)

Jurisdictional
objections.
Opposes
the
notification
requirement,
and
asserted
that
the
proposal
would
apply
to
facilities
not
subject
to
the
SPCC
rule.
(L12)

Minimum
necessary.
The
initial
notification
requirements
should
be
minimal
and
limited
to
the
information
in
Sections
I,
II,
and
III
of
Form
B.
(136)

Obsolescence.
The
information
collected
through
the
notification
form
would
quickly
become
obsolete,
but
requiring
updated
facility
notification
forms
when
changes
occur
would
be
too
burdensome.
(187,
191,
192)

Small
facilities.
The
benefit
of
having
this
information
for
small
facilities
is
not
great
enough
to
justify
requiring
these
facilities
to
expend
the
resources
to
prepare
this
information.
Recommends
that
we
initially
require
that
a
facility
exceeding
a
given
storage
capacity
(e.
g.,
42,000
gallons)
submit
this
information.
We
could
use
this
initial
information
to
evaluate
the
usefulness
of
the
information
for
all
facilities.
(58,
67,
78,
85,
91,
105,
109,
114,115,
136,
182)
Small
facilities
may
not
be
able
to
employ
sufficient
staff
to
notify
us
automatically
before
facility
operations
begin.
(101,
165,
L15)
15
Terrorists.
Putting
the
number
and
location
of
oil
storage
tanks
in
an
easily
accessible
database
could
provide
an
"intelligence
windfall"
to
terrorists
and
other
enemies
of
the
U.
S.
(132)

Wasteful.
The
proposed
notification
requirements
in
§112.1(
e)
are
wasteful,
burdensome,
and
serve
no
oil
pollution
prevention
purpose.
(31)

Outreach.
We
should
conduct
outreach,
patterned
after
the
UST
program,
to
ensure
that
owners
or
operators
are
aware
of
the
proposed
requirement.
(L6)
We
should
establish
an
information
hotline
for
the
regulated
community,
in
case
individuals
have
questions
on
how
to
complete
the
notification
form.
(168)
We
should
also
request
information
on
oil
spills.
Linking
facility
characteristics
to
spill
events
would
help
us
develop
regulations
and
define
the
universe
of
facilities
most
in
need
of
oversight.
(175)

Owner
or
operator.
Requests
clarification
on
who
must
provide
notice
when
the
owner
or
operator
of
the
facility
are
not
the
same.
(33,
48,
115,
116)

Permanently
closed
tanks.
"Does
the
Agency
intend
that
information
on
permanently
closed
tanks
be
included
in
this
notification?
"
(84)

Program
administration.
We
"found
in
review(
ing)...
the
SPCC
program
that...
numbers,
storage
capacities,
and
locations
of
aboveground
oil
storage
facilities
are
needed
to
effectively
administer
the
program"
(56
FR
54614,
Column
3).
Asks
what
we
meant
by
"effectively
administer(
ing)
the
program."
(110)

SIC
codes.
We
should
omit
the
three
"extra"
SIC
code
boxes
from
the
notification
form,
to
avoid
confusion
(33,
87);
there
were
no
codes
listed
for
edible
oil
facilities
(137);
and
the
codes
listed
were
misleading
in
that
they
did
not
cover
all
possible
industries
regulated
(155).

Accuracy.
EPA
used
inaccurate
SIC
codes.
(67,
85,
102)

Small
containers.
There
is
no
space
on
the
form
for
containers
less
than
250
gallons.
Asks
whether
we
intend
to
exclude
containers
under
250
gallons
from
the
rule.
(76)
We
should
establish
a
de
minimis
capacity
for
new
facilities
subject
to
this
regulation,
which
would
require
giving
notification
within
six
months
of
beginning
operations.
(L7)

States,
notice
to.
We
should
require
that
a
copy
of
the
notification
form
be
sent
to
the
State
Emergency
Response
Commission
(SERC)
and
Oil
Spill
Response
Agency.
Sharing
notification
information
with
SERCs
would
benefit
EPA
and
the
States.
(27)
We
should
require
an
owner
or
operator
to
inform
the
State
when
he
sends
EPA
a
notification
form.
Alternatively,
we
should
compile
notices
we
receive
and
provide
that
information
to
the
State.
(52)
16
Storage
capacity.
Requests
clarification
on
whether
only
aboveground
tanks
had
to
be
included
in
the
facility
description.
(13)
Asks
us
to
clarify
whether
total
aboveground
storage
capacity
includes
those
tanks
that
currently
store
or
will
store
oil,
or
tanks
capable
of
holding
any
substance.
(33,
115,
143)
Recommends
modifying
the
wording
to
read
"tanks
that
store
oil."
(33)
We
should
require
that
an
owner
or
operator
state
in
the
Plan,
"the
total
aboveground
storage
capacity
of
the
terminal,
the
total
of
such
capacity
that
could
be
used
for
oil,
and
the
total
of
such
capacity
at
the
time
of
reporting
that
is
actually
in
oil
storage."
(143)
Tank
size
ranges
are
not
divided
according
to
the
sizes
necessary
to
determine
if
a
facility
is
required
to
prepare
a
facility­
specific
plan
as
outlined
in
§112.
1,
that
is,
1,
320
total
gallons
or
660
gallons
for
a
single
tank.
(154)
Asks
if
additional
storage
capacity
would
trigger
a
new
notification.
(134,
165,
167)

Temporary
or
partial
storage.
EPA
should
provide
direction
regarding
partially­
filled
tanks
or
seasonally
inactive
tanks
in
Parts
II
and
III
of
the
form.
(33)
To
require
an
owner
or
operator
to
comply
with
the
proposed
notification
requirements
for
temporary
storage
created
during
an
emergency
oil
spill
response,
would
be
impractical
and
slow
down
the
response
effort.
(60)

Timetables.

Before
operations
begin.
Small
operators
may
not
be
able
to
employ
sufficient
staff
to
notify
us
automatically
before
facility
operations
begin.
(101,
165,
L15)
We
should
set
a
notification
schedule
for
such
facilities
based
on
the
new
volume
of
oil
or
oil
product
storage.
If
the
upgraded
onsite
storage
capacity
exceeds
10,000
gallons,
the
notification
deadline
should
be
prior
to
installation,
but
adds
capacity
that
trips
the
part
112
threshold.
If
the
upgrade
onsite
storage
exceeds
1,320
gallons,
the
notification
deadline
should
be
within
30
days
of
installation.
(23)
Requiring
notification
before
operations
begin
at
a
location
would
result
in
generating
useless,
duplicative,
and
contradictory
information.
(31)

Eighteen
months.
(86)

Electrical
equipment.
Asks
whether
we
would
classify
oil­
filled
equipment
like
transformers
and
oil
circuit
breakers
as
oil
storage
tanks.
If
they
are,
completing
the
notification
form
for
each
facility
with
oil­
filled
equipment
(substations)
would
take
substantially
longer
than
two
months
and
asked
for
more
time
to
complete
the
form.
(66)
If
we
regulate
facilities
with
electrical
equipment
under
part
112,
it
would
take
six
months
to
a
year
for
those
facility
owners
or
operators
to
gather
the
information
required
for
the
notification
form.
(125)

Electronic
format.
We
should
give
more
time
to
submit
the
notification
form
and
should
develop
an
electronic
form
for
owners
or
operators
to
scan.
(L11)
17
Environmentally
sensitive
areas.
Facility
owners
or
operators
needed
more
than
12
months
from
the
rule's
effective
date
to
provide
information
on
environmentally
sensitive
areas
and
adverse
weather.
(34)
If
we
require
submission
of
information
on
environmentally
sensitive
areas
and
adverse
weather
on
Form
B,
we
should
extend
the
time
to
comply
commensurate
with
the
amount
of
additional
information
required.
(95,
102)
If
we
require
submission
of
information
on
environmentally
sensitive
areas
and
the
potential
for
adverse
weather,
we
should
give
owners
or
operators
six
more
months
to
collect
the
information
so
that
data
are
accurate.
(L7)

Multiple
facilities.
"For
many
owners
of
multiple
oil
production
facilities,
it
will
be
impossible
to
complete
the
notification
process
within
the
two­
month
time
frame
proposed.
An
extension
of
the
deadline
for
filing
notifications
should
be
considered
if
an
owner
operator
is
filing
more
than
500
individual
facility
notifications.
...
We
propose
a
six
month
deadline."
(27)
Disagrees
with
the
need
for
a
separate
notification
form
for
each
facility.
(58,
71,
78,
101,
145,
165,
188,
L12,
L15)

Nine
months.
Suggests
a
nine­
month
lead
time
for
submitting
the
form,
starting
from
the
effective
date
of
the
final
regulation.
(L12)

Phase­
in.
The
two­
month
submission
period
was
unrealistic.
We
should
have
phased
reporting,
because
we
would
be
unable
to
process
the
many
thousands
of
notifications
we
would
receive
within
two­
months.
(58)
Although
it
is
logical
to
expect
the
owner
or
operator
of
a
new
refinery
to
notify
us
before
beginning
operations,
it
is
unreasonable
to
expect
such
a
notice
for
a
facility
that
is
operating
already.
(23,
28,
101,
167,
L15)

Risk.
We
should
establish
reporting
times
based
upon
risk
thresholds,
rather
than
subject
both
large
and
small
quantity
storage
facilities
to
the
same
twomonth
deadline.
(23)

Six
months.
Notification
within
a
six­
month
period
after
beginning
operations
would
be
more
reasonable,
if,
in
fact,
any
notification
is
necessary.
(101)

Six
months
to
a
year.
With
the
existing
storage
capacity
threshold
for
aboveground
storage
so
low,
many
facility
owners
or
operators
subject
to
the
rule
may
not
be
aware
of
it.
We
should
consider
adopting
new
notification
thresholds
or
a
reporting
deadline
based
on
storage
capacity
at
a
facility.
Notification
deadlines
for
facilities
with
more
than
100,000
gallons
of
capacity
could
be
due
six
months
to
one
year
earlier
than
for
facilities
with
storage
capacity
less
than
100,000
gallons.
Many
smaller
storage
facility
owners
or
operators
lack
the
resources
to
address
this
regulation.
(57,
67,
75,
91,
190,
181)
18
Six
months.
(48,
52,
71,
75,
77,
92,
105,
107,
116,
128,
133,
135,
145,
150,
155,
167,
182)

Three
or
four
months.
(87,
90,
93,
143)

Twelve
months.
(31,
34,
189,
L2,
L30)

Two
months.
Suggests
changing
the
final
sentence
of
the
subsection
to
the
following:
"With
respect
to
any
facility
subject
to
this
part
which
commences
operations
after
[insert
date
60
days
after
date
of
publication
of
final
rule]
or
becomes
subject
to
this
part
after
[insert
date
60
days
after
date
of
publication
of
the
final
rule]
as
a
result
of
increased
storage
capacity,
the
operator
must
provide
notification
to
the
Regional
Administrator
before
beginning
facility
operations."
(42)
Favor
the
notification
requirement
and
argue
that
the
proposed
notification
form
and
corresponding
two­
month
response
time
are
appropriate.
(54,
L7)
We
should
revise
the
date
of
notification
for
new
facilities
to
within
60
days
of
the
date
when
a
covered
tank
is
placed
into
operation.
(145)
Two
months
would
be
insufficient
to
collect
and
submit
such
information.
(191)
Questions
the
proposed
two­
month
time
frame.
(41,
48,
54,
58,
71,
89,
103,
175,
181,
187)

Updates
to
notification.
Facility
notification
should
be
current,
and
an
owner
or
operator
should
let
us
know
about
any
change
in
storage
capacity,
operation,
or
ownership
within
30
days.
These
commenters
recommended
making
a
full
notification
once,
and
amendments
as
necessary.
(27,
33,
89,
159,
185,
L11)

Copies
requested.
Several
States
requested
copies
of
the
notifications
EPA
would
receive
(52,
185,
L10)

Vegetable
oil
and
animal
fat
facilities.
Including
vegetable
and
animal
oils
in
the
definition
of
oil
was
unreasonable.
The
CWA's
context
shows
that
Congress
did
not
intend
to
address
vegetable
and
animal
oils
under
the
SPCC
program.
(42)
We
should
ask
for
less
information
from
vegetable
oil
facilities
(i.
e.,
name,
address,
number
of
tanks,
and
total
capacity
of
tanks).
(56)

Response:
Withdrawal
of
proposal.
We
have
decided
to
withdraw
the
proposed
facility
notification
requirement
because
we
are
still
considering
issues
associated
with
establishing
a
paper
versus
electronic
notification
system,
including
issues
related
to
providing
electronic
signatures
on
the
notification.
Should
the
Agency
in
the
future
decide
to
move
forward
with
a
facility
notification
requirement,
we
will
repropose
such
requirement.

II
­
B:
Content
of
notification
form
Comments:
Addresses
and
zip
code.
"It
won't
be
possible
to
give
an
address
and
zip
code
of
the
facility
[sic]
due
to
their
rural
location."
(28,
42,
101)
A
single
regional
19
production
office
can
monitor
or
operate
many
different
production
facilities.
We
should
clarify
whether
the
Agency
wants
the
address
of
the
production
office
or
the
legal
description
of
where
the
facility
is
located.
(42)
Crude
oil
production
storage
facilities
do
not
have
a
name,
address,
and
zip
code.
(58,
187)
We
should
ask
for
separate
facility
location
and
facility
mailing
addresses
so
we
could
later
avoid
mailing
information
to
an
unattended
facility.
(101)
We
should
allow
either
the
facility
address
or
location
to
suffice
for
notification
purposes.
(133)

Authority.
Some
of
the
information
we
proposed
requesting
is
beyond
our
authority
to
collect
(e.
g.,
facility
latitude
and
longitude,
location
of
environmentally
sensitive
areas,
and
potential
for
adverse
weather).
(L30)

Private
wells.
If
we
adopt
the
notification
requirement,
we
should
not
include
private
water
wells
in
the
list
of
water
suppliers
that
the
owner
or
operator
must
notify.
It
would
be
highly
impractical
and
prohibitively
expensive
for
the
owner
or
operator
to
attempt
to
locate
every
downstream
private
water
well.
(28,
101)

Dun
&
Bradstreet.
Dun
&
Bradstreet
numbers
are
not
available
for
crude
oil
production
storage
facilities.
(58)
Obtaining
Dun
&
Bradstreet
numbers
can
be
very
labor
intensive
or
impossible.
(42,
L12)
We
should
make
identification
of
Dun
&
Bradstreet
numbers
optional
and
not
punish
facility
owners
or
operators
if
they
do
not
provide
Dun
&
Bradstreet
numbers
or
if
they
provide
inaccurate
ones.
(L12)

Longitude
and
latitude.
The
facility's
latitude
and
longitude
should
be
included
on
the
notification
form.
(27,
62,
121,
135,
154,
168,
L11)

Miscellaneous
items.
We
should
collect
aboveground
storage
tank
information,
such
as
tank
status
(e.
g.,
currently
in
use),
capacity,
age,
material
of
construction,
method
of
construction
(e.
g.,
field
erected),
and
substance
stored.
(44)
Supports
a
requirement
that
the
owner
or
operator
submit
additional
information
on
the
notification
form,
including
facility
latitude
and
longitude,
location
of
environmentally
sensitive
areas,
potable
water
supplies,
presence
of
secondary
containment,
spill
history,
leak
detection
equipment
and
alarms,
age
of
tanks,
and
potential
for
adverse
weather.
(168)
Opposes
a
requirement
that
the
owner
or
operator
provide
additional
information,
such
as
the
latitude
and
longitude
of
the
facility,
location
of
environmentally
sensitive
areas
and
potable
water
supplies,
presence
of
secondary
containment,
spill
history,
leak
detection
equipment
and
alarms,
age
of
tanks,
potential
for
adverse
weather,
and
any
other
additional
information.
(31,
33,
34,
35,
41,
42,
48,
51,
53,
54,
57,
58,
62,
66,
67,
75,
79,
82,
83,
86,
87,
89,
91,
95,
101,
102,
103,
110,
115,
118,
121,
133,
136,
137,
155,
164,
167,
181,
182,
183,
191,
L12,
L30).

Navigable
waters.
Asks
us
to
clarify
what
we
meant
in
the
proposed
rule
when
we
stated
that
an
owner
or
operator
should
provide
the
"distance
to
nearest
navigable
waters"
in
proposed
§112.1(
e)(
2)(
iii).
Asks
whether
we
meant
the
owner
or
operator
should
consider
tributaries,
wetlands,
and
sloughs
when
determining
the
distance
to
nearest
navigable
waters.
(62)
We
should
define
navigable
waters
on
the
form.
(76)
20
A
facility's
distance
from
"navigable
waters"
may
be
meaningless
when
storm
drains
are
located
next
to
the
facility
because
spilled
oil
can
travel
directly
through
a
storm
drain
to
navigable
waters.
(79)
Information
on
distance
to
navigable
waters
is
limited
and
open
to
various
interpretations.
(39,
48,
79)
An
owner
or
operator
may
be
incapable
of
identifying
the
nearest
navigable
water.
(42,
58)
Notification
should
"not
include
the
distance
of
the
facility
to
the
nearest
navigable
waters,
but
the
distance
of
each
tank
from
the
nearest
navigable
waters."
(L2)
Requesting
the
distance
to
navigable
waters
for
the
nearest
tank
would
unduly
skew
the
database
for
certain
industries.
It
would
be
better
to
obtain
information
on
estimated
average
distances
for
each
category
in
Section
II
of
the
notification
form.
(L12)

"Site
information."
We
should
make
some
"technical
corrections"
to
improve
the
notification
form,
but
gave
no
specifics.
(48)
We
should
ask
only
for
site
information
and
should
include
"a
question
regarding
the
need
to
implement
a
facility
SPCC
Plan."
(89)

Response:
See
the
response
to
II­
A,
above.
21
Category
III:
Discretionary
provisions
III
­
A:
Stating
the
design
capabilities
of
drainage
systems
Background:
In
1991,
we
requested
comments
on
a
recommendation
that
we
did
not
include
in
rule
text
that
an
owner
or
operator
of
an
onshore
facility
(other
than
a
production
facility)
describe
the
design
capability
of
a
facility
drainage
system
in
the
SPCC
Plan
if
the
system
is
relied
upon
to
control
spills
or
leaks.

Comments:
Support
for
description.
We
should
require
that
owners
or
operators
describe
the
design
capabilities
of
facility
drainage
systems
in
the
SPCC
Plan.
Such
a
description
would
help
identify
all
paths
of
escape
for
discharges
at
a
facility,
assess
the
spill
retention
capacity
of
the
facility's
containment
system,
and
identify
the
risks
to
the
public
of
a
discharge.
(47,
51,
76,
80,
95,
135,
168,
L17)

Large
or
small
facilities.
EPA
should
require
more
detailed
drainage
information
for
large
facilities
with
storage
capacity
exceeding
1,000,000
gallons.
At
these
facilities,
a
Professional
Engineer
(PE)
should
identify
all
paths
of
escape
for
oil
discharges,
assess
the
spill
detention
capacity
of
the
facility,
identify
the
risks
of
a
release
to
the
public,
and
develop
topographic
surveys
of
each
facility
and
the
area
immediately
surrounding
the
facility.
(47)

Requirement
or
recommendation.
We
should
recommend
–
rather
than
require
–
an
owner
or
operator
to
describe
facility
drainage
system
design
capabilities
in
the
SPCC
Plan.
The
provision
is
redundant
since
other
SPCC
rule
provisions
already
address
this
issue.
(95,
175)
Describing
the
facility
drainage
system
design
capabilities
would
create
unnecessary
paperwork
and
complicate
the
Plan.
(25,
34,
74,
155)

Storm
event.
SPCC
Plans
should
describe
the
maximum
storm
event
the
drainage
system
can
handle.
It
would
be
essential
to
know
if
the
capabilities
of
the
existing
system
were
adequate
to
handle
storm,
spill,
or
leak
flows.
(80)

Response:
The
question
of
description
of
the
design
capabilities
of
drainage
systems
for
onshore
facilities
other
than
production
facilities
is
adequately
covered
by
rules
pertaining
to
drainage.
See,
for
example,
§§
112.7(
a)(
3)
and
(4),
112.7(
b),
112.8(
b),
and
112.10(
c).
Therefore,
we
will
not
promulgate
any
additional
requirements
on
this
subject.
These
provisions
generally
require
that
a
facility
owner
or
operator
design
the
facility
drainage
system
to
prevent
discharges,
or
if
prevention
fails,
to
contain
the
discharge
within
the
facility.

We
note
that
for
facilities
with
a
storage
capacity
exceeding
1,000,000
gallons,
we
do,
in
some
cases,
require
more
detailed
drainage
information
(in
the
facility
response
plan).
22
III
­
B:
Different
requirements
for
large
and
small
facilities
Background:
In
1991,
we
requested
comments
on
whether
to
create
a
category
for
large
facilities
and
to
require
more
stringent
provisions
for
such
facilities.
We
also
requested
comments
on
whether
such
provisions
should
be
discretionary
for
smaller
facilities.

Comments:
Authority.
Neither
the
language
nor
the
legislative
history
of
the
CWA
compels
us
to
regulate
all
facilities
at
which
oil
is
present.
(65,
125)
The
statute
confers
substantial
discretion
on
us
to
determine
the
types
of
facilities
that
pose
sufficient
risk
to
surface
waters
to
warrant
the
SPCC
regulatory
controls.
(125)

Opposition
to
proposal.
All
facilities
can
pose
major
impacts
to
human
health
and
to
the
environment,
regardless
of
storage
capacity.
(168)

Unnecessary.
Such
provisions
are
unnecessary
because
no
risks
exist
for
which
the
discretionary
provisions
were
proposed.
(35,
82)

Support
for
proposal.
"Contrary
to
EPA's
concern,
§311(
j)(
1)(
C)
of
the
Clean
Water
Act
does
not
prohibit
different
requirements
based
on
facility
size."
(65)
We
should
regulate
facilities
based
on
storage
capacity
differences.
We
should
distinguish
between
small
and
large
facilities.
Even
small
cost
increases
can
have
a
detrimental
economic
effect
on
small
facilities.
(62,
65,
82,
115,
145,
164,
173,
175,
L6)
EPA's
departure
from
the
Task
Force's
recommendations
to
regulate
facilities
based
on
size
"undermines
EPA's
assertion
that
the
proposed
regulations
are
justified
by
the
Task
Force
Report."
(32)
Supports
regulation
of
facilities
that
could
reasonably
be
expected
to
discharge
oil
in
harmful
quantities.
(75)
We
should
have
separate
requirements
for
small
and
large
facilities.
"Aboveground
tanks
used
by
production
wells
are
considerably
smaller
than
those
used
in
the
refining
and
marketing
sectors.
Further,
these
wells
typically
are
remote
from
both
major
surface
waters
and
population
centers,
thus
posing
significantly
less
risk
to
the
environment
than
larger
facilities."
(125)
Cites
EPA's
finding
in
the
1988
Underground
Storage
Tank
(UST)
final
rule
that
"tanks
that
hold
large
amounts
of
regulated
substances
do
pose
a
relatively
larger
potential
danger
to
human
health
and
the
environment
than
other,
small
tanks."
(See
53
FR
37111.)
We
should
use
the
UST
finding
in
the
SPCC
rule.
(125,
170)

Risk.
We
should
focus
on
facilities
that
pose
the
greatest
risk
to
navigable
waters,
rather
than
focus
on
facilities
of
a
particular
size.
(35,
50,
62,
79,
82,
114,
125,
130,
164,
167,
L17)
We
should
focus
on
the
engineering
and
design
of
the
storage
and
containment
plan.
(35)
We
should
limit
the
requirements
to
high­
risk
facilities,
and
not
to
facilities
with
contingency
plans
and
spill­
prevention
measures
in
place.
(62)
We
should
not
propose
broad
changes
to
part
112
that
would
apply
to
all
storage
facilities
regardless
of
tank
size,
without
considering
the
potential
impacts
on
navigable
waters.
However,
the
final
rule
should
be
flexible,
and
should
account
for
site­
specific
factors
and
conditions
regarding
potential
environmental
impacts.
(114)
Instead
of
imposing
the
same
requirements
on
all
facilities
regardless
of
facility
size
or
level
of
risk,
we
23
should
design
a
regulatory
structure
to
impose
pollution
prevention
costs
equal
to
the
pollution
"costs"
that
a
facility
may
impose
on
the
public.
(125)
By
imposing
the
same
requirements
and
costs
on
smaller,
lower
risk
facilities
as
on
larger,
higher
risk
facilities
regulatory
costs
outweigh
environmental
benefits.
(130)

Large
facilities,
more
stringent
requirements.
We
should
regulate
large
facilities
more
stringently
because
they
can
bear
the
cost
of
regulations
more
easily
than
smaller
ones.
(101)
We
should
regulate
large
facilities
more
stringently
than
small
facilities
because
large
facilities
pose
a
greater
hazard
to
the
environment
than
small
facilities.
We
should
modify
SPCC
regulations
to
reflect
varying
degrees
of
stringency
based
on
facility
size,
and
the
observation
that
large
facilities
have
a
greater
potential
for
causing
spills
and
subsequent
environmental
damage.
(32,
58,
65,
125)
The
proposed
regulations
"focus
on
aboveground
storage
tanks
with
a
capacity
of
one
million
gallons
and
larger."
(108,
122)

Small
facilities
only.
We
should
apply
discretionary
provisions
to
small
facilities
only,
leaving
requirements
only
for
larger
facilities.
(51,
80,
103,
L17)

Small
facilities,
more
stringent
requirements.
Small
facilities
may
pose
a
greater
spill
potential
because
small
facility
owners
or
operators
do
not
have
resources
to
ensure
proper
equipment
installation.
(76)
A
large
facility
is
more
likely
to
have
sufficient
human
resources
and
equipment
than
a
small
facility.
In
the
event
of
a
spill,
a
large
facility
can
provide
immediate
response,
thus
minimizing
the
spill
size.
(102)

Response:
Large
or
small
facility
regulation,
in
general.
We
have
decided
not
to
regulate
facilities
differently
based
merely
on
storage
capacity,
provided
that
the
capacity
is
above
the
regulatory
threshold
of
over
1,
320
gallons.
This
decision
is
based
on
environmental
reasons.
Small
discharges
of
any
type
of
oil
that
reach
the
environment
can
cause
significant
harm.
Sensitive
environments,
such
as
areas
with
diverse
and/
or
protected
flora
and
fauna,
are
vulnerable
to
small
spills.
EPA
noted
in
a
recent
denial
of
a
petition
for
rulemaking:
"Small
spills
of
petroleum
and
vegetable
oils
and
animal
fats
can
cause
significant
environmental
damage.
Real­
world
examples
of
oil
spills
demonstrate
that
spills
of
petroleum
oils
and
vegetable
oils
and
animal
fats
do
occur
and
produce
deleterious
environmental
effects.
In
some
cases,
small
spills
of
vegetable
oils
can
produce
more
environmental
harm
than
numerous
large
spills
of
petroleum
oils."
62
FR
54508,
54530,
October
20,
1997.
Describing
the
outcome
of
one
small
spill
of
400
gallons
of
rapeseed
oil
into
Vancouver
Harbor,
we
noted
that
"...
88
oiled
birds
of
14
species
were
recovered
after
the
spill,
and
half
of
them
were
dead.
Oiled
birds
usually
are
not
recovered
for
3
days
after
a
spill,
when
they
become
weakened
enough
to
be
captured.
Of
the
survivors,
half
died
during
treatment.
The
number
of
casualties
from
the
rapeseed
oil
spills
was
probably
higher
than
the
number
of
birds
recovered,
because
heavily
oiled
birds
sink
and
dying
or
dead
birds
are
captured
quickly
by
raptors
and
scavengers."
62
FR
54525.

A
small
discharge
may
also
cause
harm
to
human
health
or
life
through
threat
of
fire
or
explosion,
or
short­
or
long­
term
exposure
to
toxic
components.
24
Other
factors.
Finally,
EPA
notes
that
the
rule
affords
flexibility
to
an
owner
or
operator
of
a
facility
to
design
a
Plan
based
on
his
specific
circumstances.
It
allows
him
to
choose
methods
that
best
protect
the
environment.
It
permits
deviations
from
most
of
the
mandatory
substantive
requirements
of
the
rule
when
the
facility
owner
or
operator
can
demonstrate
a
reason
for
nonconformance,
and
can
provide
equivalent
environmental
protection
by
other
means.
Consequently,
both
small
and
large
facilities
have
the
opportunity
to
reduce
costs
by
alternative
methods
if
they
can
maintain
environmental
protection.
Because
smaller
facilities
may
require
less
complex
plans
than
larger
ones,
their
costs
may
be
less.
In
addition,
small
facilities
storing
or
using
1,320
gallons
or
oil
or
less
will
not
be
subject
to
the
rule.

III­
B­
1
Defining
"small"
and
"large"
facility
Comments:
Alternate
small
facility
definitions.

Less
than
126,000
gallons.
Less
than
126,000
gallons
of
total
aboveground
storage
capacity.
(133)

Less
than
30,000
gallons.
Less
than
30,000
gallons
of
total
aboveground
storage
capacity.
(82)

Less
than
10,000
gallons.
Less
than
10,000
gallons
of
total
oil
storage
capacity.
(L17).

"Less
than
42,000
gallons."
Less
than
42,000
gallons
of
total
aboveground
storage
capacity
(34,
67,
78,
133,
and
167);
less
than
42,000
gallons
of
total
oil
storage
capacity,
provided
no
single
tank
is
greater
than
12,600
gallons
(58);
If
we
define
a
small
facility
as
one
with
less
than
42,
000
gallons
of
total
aboveground
storage
capacity,
we
would
reduce
the
burden
on
numerous
small
operations,
without
limiting
the
protection
afforded
by
spill
prevention,
containment,
and
countermeasures.
(78)
Less
than
42,000
gallons
total
storage
capacity,
provided
no
single
container
is
greater
than
250
gallons.
(133)

242,000
gallons.
We
should
define
a
small
facility
as
a
"facility
with
a
total
of
242,000
gallons
or
less
of
oil,
provided
no
single
container
has
[a]
capacity
in
excess
of
20,000
gallons."
(70)

Large
facility
definition.

More
than
10,000
gallons.
A
large
facility
should
be
one
with
a
capacity
of
10,
000
BBI
(4.
2
million
gallons).
This
approach
would
be
more
reasonable
and
would
recognize
the
greater
threat
presented
by
a
spill
occurring
at
a
facility
with
that
amount
of
storage
capacity.
(34)

More
than
42,000
gallons.
Supports
the
42,000
gallon
capacity
criteria,
but
suggests
that
small
and
large
facilities
be
further
delineated.
(62)
We
should
25
define
a
large
facility
as
one
with
a
regulated
storage
capacity
of
more
than
42,000
gallons.
(78,105)

Response:
Because
we
do
not
differentiate
requirements
merely
due
to
facility
size,
there
is
no
need
to
define
large
or
small
facility.

III­
B­
2
Small
facility
exemption
Comments:
Support
for
small
facility
exemption.
We
should
exempt
small
facilities
from
this
regulation.
(28,
46,
58,
67,
70,
82,
101,
67)
Such
an
exemption
would
be
consistent
with
the
Task
Force
findings.
(28)
An
exemption
would
reduce
the
regulatory
burdens
because
owners
or
operators
would
then
be
subject
to
local
requirements.
(46)
We
should
exempt
small
facilities
because
we
would
realize
a
more
significant
environmental
benefit
from
taxpayer's
dollars
by
focusing
scarce
funds
and
resources
on
larger
facilities.
(58)
In
setting
an
exemption,
we
should
consider
size
and
whether
the
facility
is
one
or
more
miles
from
surface
waters
or
outside
of
the
coastal
zone.
(167,
174)

Opposition
to
proposal.
We
have
not
provided
a
"reasoned"
analysis
for
applying
the
proposed
revisions
to
small
facilities.
(58)
We
should
gather
additional
information
to
justify
our
changes
to
the
SPCC
program.
Cites
the
GAO
report,
and
asserts
that
we
need
more
information
to
decide
which
tanks
to
regulate
most
strictly
and
inspect
most
often.
(101)
We
did
not
provide
a
historical
background,
or
an
understanding
of
exploration
and
production
or
gas
processing
industry
spills.
(114)

Recommendations
instead.
Questions
whether
all
of
the
proposed
changes
in
the
rule
are
necessary
for
all
types
and
sizes
of
oil
storage
facilities,
including
smaller
tank
configurations
such
as
those
found
at
oil
and
gas
production
sites,
quick
oil
change
facilities,
and
other
points
of
oil
sales
and
distribution.
(70)
The
newly
proposed
requirements
should
remain
as
recommendations
for
small
facilities.
(67,
L18)

Risk.
The
regulation
should
not
focus
on
small,
aboveground
storage
tanks,
which
pose
fewer
environmental
risks
than
large
tanks.
(50,
67,
79)
We
should
apply
the
revisions
to
large
facilities
only,
and
maintain
the
status
quo
for
smaller,
less
environmentally
threatening
facilities.
(58)
The
current
SPCC
regulations
and
industry
standards
provide
sufficiently
for
continued
environmental
protection.
(67)
We
should
exempt
certain
smaller,
low
risk
tanks
and
temporarily
closed
tanks.
(71)
We
should
exempt
facilities
that
have
no
reasonable
potential
to
discharge
oil
into
navigable
waters.
(75)

We
should
not
require
small
facilities
to
have
SPCC
Plans,
as
long
as
the
facility's
HAZWOPER
or
hazardous
waste
contingency
plan
contains
oil­
related
spill
response
procedures.
(62,
124)
"Problems
exist"
in
the
proposed
regulations,
with
respect
to
smaller
aboveground
tanks
in
the
660
to
10,000
gallon
range
capacity
storage
(108),
and
with
smaller
aboveground
tanks
in
the
660
to
20,000
gallon
range
capacity
storage
(122).
Storage
tanks
in
the
600
to
4,200
gallon
storage
capacity
range
neither
have
26
the
same
potential
adverse
impact
nor
require
the
same
intense
scrutiny
as
very
large
tanks.
(105)
Our
data
do
not
demonstrate
that
small
facilities
cause
significant
discharge
hazards
to
navigable
waters.
(31,
34,
101,
and
110)

Small
shop­
built
containers.
Smaller,
factory­
constructed
tanks
have
fewer
field
construction
problems
and
hold
less
oil
than
large
tanks.
Eliminating
small
tanks
from
the
proposed
requirements
would
result
in
a
more
cost­
effective
regulatory
program
with
environmental
protection
equivalent
to
part
112
requirements.
(164)

Response:
As
noted
in
this
section,
we
are
not
regulating
small
facilities
differently
from
large
facilities.
See
the
discussion
in
section
V
­
G
of
this
document
concerning
the
rise
in
the
regulatory
threshold.

Recommendations
instead.
We
are
not
including
any
recommendations
in
the
rules
because
we
do
not
wish
to
confuse
the
regulated
public
as
to
what
is
mandatory
and
what
is
discretionary.

Risk.
We
do
consider
the
size
of
a
facility
and
whether
its
location
gives
rise
to
the
reasonable
possibility
of
discharge
as
described
in
§112.
1(
b),
for
example
the
distance
of
the
facility
from
the
nearest
navigable
waters
or
adjoining
shorelines.

III­
B­
3
Alternative
regulatory
approaches
for
small
facilities
Comments:
Specific
rules,
production
facilities.
We
should
develop
a
subset
of
regulations
to
specifically
address
operations
of
small
oil
and
gas
production
facilities
with
a
storage
capacity
of
less
than
42,000
gallons.
(28)

Less
than
an
SPCC
Plan.
Facilities
with
hundreds
of
small
capacity
storage
tanks
(50
barrels
or
less)
should
be
required
to
meet
spill
prevention
measures
but
not
prepare
an
SPCC
Plan,
or
meet
the
other
requirements
associated
with
the
SPCC
rules.
The
potential
for
major
environmental
damage
from
these
facilities
is
remote
because
these
facilities
hold
small
volumes
of
oil.
(71)

Response:
Specific
rules,
production
facilities.
Because
we
do
not
regulate
facilities
based
on
size,
there
is
no
need
for
regulations
specifically
addressed
to
any
type
of
facility
for
that
reason.
We
note
that
different
sections
of
the
final
rule
address
production
facilities.
For
example,
§112.
9
addresses
requirements
for
onshore
production
facilities.
Section
112.
10
addresses
requirements
for
onshore
oil
drilling
and
workover
facilities.
Section
112.
11
addresses
requirements
for
offshore
drilling,
production,
or
workover
facilities.

Less
than
an
SPCC
Plan.
We
disagree
that
meeting
the
rule's
requirements
without
preparing
and
implementing
a
Plan
would
protect
the
environment.
There
would
be
no
way
to
enforce
those
requirements
in
the
absence
of
a
written
facility­
specific
Plan.
Category
IV:
General
applicability
and
notification
27
Category
IV:
General
applicability
and
notification
IV­
A:
Scope
of
the
rule
­
"Harmful
quantities"
­
§112.1(
a),
(b),
(c),
and
(d)(
1)

Background:
Section
112.1(
a)
of
the
current
rule
seeks
to
prevent
oil
discharges
into
the
"navigable
waters
of
the
United
States
or
adjoining
shorelines."
In
§112.1(
a),
(b),
and
(c)
of
the
1991
proposed
rule,
we
proposed
to
extend
the
geographic
scope
of
the
SPCC
regulation
to
conform
with
the
1977
CWA
amendments.
CWA
section
311(
b)(
1),
as
amended
in
1977,
prohibits
oil
or
hazardous
substance
discharges
into
United
States
navigable
waters
or
adjoining
shorelines,
or
into
the
waters
of
the
contiguous
zone,
or
in
connection
with
activities
under
the
Outer
Continental
Shelf
Lands
Act
or
the
Deepwater
Port
Act
of
1974,
or
that
may
affect
natural
resources
belonging
to,
appertaining
to,
or
under
the
exclusive
management
authority
of
the
United
States,
including
resources
under
the
Magnuson
Fishery
Conservation
and
Management
Act.

We
also
proposed
to
revise
the
term
harmful
quantities
in
§112.1(
b)
to
reflect
the
1978
amendments
to
the
CWA.
The
revised
term
–
quantities
that
may
be
harmful,
as
described
in
part
110
of
this
chapter
–
includes
oil
discharged
in
quantities
that
violate
applicable
water
quality
standards,
cause
a
film
or
sheen
upon
or
discoloration
of
the
surface
of
the
water
or
adjoining
shorelines,
or
cause
a
sludge
or
emulsion
to
be
deposited
beneath
the
surface
of
the
water
or
upon
adjoining
shorelines.
See
40
CFR
110.3.
Amendments
to
the
CWA
also
reflected
the
broadening
of
quantities
that
may
be
harmful
to
include
those
not
only
harmful
to
the
"public
health
or
welfare,"
but
also
to
the
environment.

IV­
A­
1
Extending
the
geographic
scope
of
the
rule
Comments:
NRDAs.
Proposal
"will
allow
for
more
clarity
in
determining
which
facilities
are
subject
to
the
SPCC
requirements.
Also,
the
inclusion
of
natural
resources
sets
the
stage
for
the
implementation
of
Natural
Resources
Damage
Assessments,
as
required
by
OEPA."
(27)

Opposition
to
proposal.
"If
natural
resources
in
this
context
means
all
Federal
lands,
then
this
extension
would
bring
under
the
scope
of
40
CFR
112
a
significant
number
of
operating
facilities
which
did
not
previously
require
SPCC
plans.
The
proposed
rule,
however,
states
that
EPA
assumes
existing
facilities
that
would
be
brought
under
40
CFR
112
regulation
already
have
SPCC
Plans
for
other
reasons,
and
thus
expects
the
rule
to
affect
only
new
facilities.
This
is
incorrect;
many
existing
facilities
on
federal
lands
do
not
have
SPCC
plans
because
they
have
had
no
need
and
no
regulatory
requirement
for
them.
For
example,
our
facilities
in
arid
areas
where
there
is
little
or
no
surface
water
or
rainfall
lack
such
plans
because
of
their
location
and
the
nature
of
their
activities.
Thus,
the
regulations
should
be
revised
to
better
distinguish
which
existing
or
new
facilities
warrant
SPCC
plans
based
on
their
location
and
the
nature
of
their
activities."
(63)
28
Coastal
zone.

Exclude.
"...
RMOGA
suggests
consideration
be
given
to
adding
requirements
that
the
exempt
facilities
be
those
located
1
or
more
mile(
s)
from
surface
waters
(defined
as
those
for
which
water
quality
standards
are
assigned)
or
those
located
outside
of
the
coastal
zone
(as
already
defined
by
regulation)."
(167)

Include.
"The
suggested
reference
to
the
coastal
zone
is
appropriate
because
this
is
a
clearly
defined
area
and
is
the
area
where
greatest
benefits
from
the
proposed
rules
can
be
expected."
Areas
less
than
one
mile
from
a
river,
lake
or
stream
should
be
excluded
from
the
coastal
zone
definition.
(174)

Magnuson
Act
resources
only.
Expansion
of
applicability
to
include
natural
resources
"will
surely
result
in
another
unnecessary
workload
on
the
judicial
system
over
the
years.
Perhaps
the
replacement
of
this
item
with
the
following
wording
will
minimize
or
eliminate
the
impact:
`...
or
any
resources
under
the
Magnuson
Fishery
Conservation
and
Management
Act'."
(L12)

Response:
We
also
believe
that
few,
if
any,
new
facilities
will
be
subject
to
the
rule
because
of
its
extension
to
facilities
with
the
potential
to
affect
certain
natural
resources.
We
believe
that
most
affected
facilities
are
either
already
subject
to
the
rule,
or
not
subject
to
our
jurisdiction
due
to
a
Memorandum
of
Understanding
between
EPA,
the
U.
S.
Department
of
Transportation
(DOT),
and
the
U.
S.
Department
of
the
Interior
(DOI),
which
assigns
jurisdiction
over
most
of
those
facilities
to
DOT
or
DOI.
See
40
CFR
part
112,
Appendix
B.

We
have
amended
this
provision
to
be
consistent
with
the
revised
statutory
language
found
in
sections
311(
b)(
1)
and
(c)(
1)(
A)
of
the
CWA.
This
rule
focuses
on
preventing
discharges
to
navigable
waters,
adjoining
shorelines,
the
exclusive
economic
zone,
and
natural
resources
belonging
to,
appertaining
to,
or
under
the
exclusive
jurisdiction
of
the
United
States.
Once
a
prohibited
discharge
of
oil
occurs
and
affects
such
natural
resources,
the
NRDA
provisions
of
OPA
sections
1002(
b)(
2)(
A)
and
1006
apply.
The
National
Oceanographic
and
Atmospheric
Administration
has
promulgated
a
set
of
regulations
which
govern
the
process
for
conducting
NRDAs
under
the
OPA.
15
CFR
part
990.

IV­
A­
2
Broadening
the
concept
of
harmful
quantities
Comments:
Support
for
proposal.
"Pratt
&
Whitney
also
agrees
with
the
revision
of
section
112.1(
b)
definition
of
`harmful
quantities'
to
reflect
those
of
the
Clean
Water
Act
amendments.
This
effort
at
consistency
helps
business
achieve
compliance."
(118)

Opposition
to
proposal.
Our
proposal
would
"replace
a
fairly
objective
standard
with
a
very
subjective
conditional
standard,"
and
asserted
that
the
language
in
the
current
rule
29
provides
adequate
environmental
protection.
(35)
We
should
expand
the
definition
of
a
harmful
quantity
to
include
used
oils
or
waste
forms
of
all
subject
products.
(87)
One
person
asked
that
we
describe
how
we
will
determine
whether
a
quantity
"may"
be
harmful,
and
who
will
make
this
determination.
(111)
While
our
proposed
change
implies
a
standard
of
reasonable
risk,
the
applicable
part
110
definition
"creates
an
entirely
different
standard."
Part
110
provides
that
any
discharge
that
causes
a
film
or
sheen
upon
or
discoloration
of
the
surface
of
the
water
or
adjoining
shorelines
is
deemed
to
be
a
discharge
of
oil
that
"may
be
harmful."
(125)
We
should
modify
the
applicability
standard
to
base
the
program
on
"real"
or
"reasonable"
risks
to
navigable
waters,
rather
than
on
"de
minimis"
or
"theoretical"
risks,
to
reduce
the
regulatory
burden.
(98,
125,
170)

Facility
notification.
Our
proposal
would
subject
more
owners
or
operators
to
the
§112.1
notification
requirements.
(65,
98)

Manmade
structures.
Our
risk
criteria
in
determining
applicability
to
the
SPCC
requirements
are
too
broad,
particularly
with
regard
to
the
sheen
test
and
the
"prohibition
of
considering
manmade
structures"
to
evaluate
a
facility's
risk.
(98)
We
should
change
the
regulation
to
permit
an
owner
or
operator
to
consider
manmade
structures
that
provide
containment
in
determining
whether
a
facility
could
reasonably
be
expected
to
have
a
spill
event.
Such
a
consideration
is
appropriate
"where
the
structures
are
inherent
in
the
design
of
the
facility
and
serve
functional
and
operational
purposes."
(78,
98,
125,
156,
170)

NPDES
rules.
Our
definition
of
harmful
quantities
does
not
appear
to
reflect
the
National
Pollutant
Discharge
Elimination
System
(NPDES)
storm
water
discharge
permit
requirements.
We
should
consider
the
protection
provided
by
NPDES
permits
and
the
Underground
Storage
Tank
(UST)
regulation
(part
280)
sufficient.
(76)

Paperwork.
Our
proposal
appears
to
conflict
with
section
101(
f)
of
the
Clean
Water
Act
(CWA)
that
requires
EPA
to
minimize
paperwork,
duplication,
and
delays
in
implementing
the
statute.
(65)

Reasonable
expectation
of
discharge.
We
should
clarify
the
statement
in
the
proposed
rule
that
part
112
applies
to
owners
or
operators
of
non­
transportation­
related
facilities,
"which
due
to
their
location
could
reasonably
be
expected
to
discharge
oil
in
quantities
that
may
be
harmful,
described
in
part
110."
This
is
particularly
important
because
of
the
associated
penalties
for
noncompliance.
(62,
89,
98,
111,
149,
154)

Sheens.
What
makes
a
sheen
harmful?
(62)

Response:
Support
for
proposal.
We
appreciate
commenter
support.

Applicability.
Quantities
of
oil
that
may
be
harmful
include
oil
discharged
in
quantities
that
violate
applicable
water
quality
standards,
cause
a
film
or
sheen
upon
or
discoloration
of
the
surface
of
the
water
or
adjoining
shorelines,
or
cause
a
sludge
or
30
emulsion
to
be
deposited
beneath
the
surface
of
the
water
or
upon
adjoining
shorelines.
The
revision
we
have
made
to
this
provision
simply
reflects
the
1978
amendment
to
the
CWA,
which
requires
us
to
determine
quantities
of
oil
that
may
be
harmful,
rather
than
quantities
of
oil
that
will
be
harmful.
The
harm
a
discharge
may
cause
will
vary
from
site
to
site
depending
upon,
for
example,
the
sensitivity
of
the
environment,
the
water
conditions,
etc.
These
quantities
apply
to
discharges
of
used
oil
or
waste
oil
as
well
as
any
other
type
of
oil.
The
1987
amendments
to
part
110
incorporated
this
statutory
change,
but
retained
the
same
objective
criteria
as
before
–
violation
of
applicable
water
quality
standards,
a
film
or
sheen
on
the
surface,
or
a
sludge
or
emulsion
below
the
surface.
Thus,
this
revision
to
our
SPCC
rule
should
not
result
in
a
change
in
the
number
of
regulated
entities.

Facility
notification.
We
have
withdrawn
the
proposal
for
facility
notification.

Manmade
structures.
To
allow
consideration
of
manmade
structures
(such
as
dikes,
equipment,
or
other
structures)
to
relieve
a
facility
from
being
subject
to
the
rule
would
defeat
its
preventive
purpose.
Because
manmade
structures
may
fail,
thus
putting
the
environment
at
risk
in
the
event
of
a
discharge,
there
is
an
unacceptable
risk
in
using
such
structures
to
justify
relieving
a
facility
from
the
burden
of
preparing
a
prevention
plan.
Secondary
containment
structures
should
be
part
of
the
prevention
plan.

NPDES
rules.
We
do
consider
the
protection
provided
by
NPDES
permits
and
the
Underground
Storage
Tank
(UST)
regulation
(part
280)
in
the
rule.
An
owner
or
operator
may
use
his
Best
Management
Practice
Plan
(BMP)
prepared
under
an
NPDES
permit
as
an
equivalent
SPCC
Plan,
if
the
plan
provides
protections
equivalent
to
SPCC
Plans.
Not
all
BMP
plans
will
qualify,
as
some
BMP
plans
might
not
provide
equivalent
protection.
NPDES
permits
without
BMP
plans
would
not
qualify.

We
exempt
from
the
SPCC
program
completely
buried
tanks
subject
to
all
of
the
technical
requirements
of
40
CFR
part
280
or
a
State
program
approved
under
40
CFR
part
281.

Paperwork.
We
disagree
that
our
proposal
conflicts
with
section
101(
f)
of
the
Clean
Water
Act
(CWA)
that
requires
EPA
to
minimize
paperwork,
duplication,
and
delays
in
implementing
the
statute.
The
expansion
of
the
geographical
scope
of
the
rule
tracks
the
1978
statutory
amendments.

Reasonable
expectation
of
discharge.
We
do
not
believe
that
any
rule
which
exempts
facilities
beyond
any
particular
distance
meets
the
intent
of
the
statute.
The
locational
standard
in
the
rule
is
whether
there
is
a
reasonable
possibility
of
discharge
in
quantities
that
may
be
harmful
from
the
facility.
A
facility
that
is
more
than
one
mile
from
navigable
waters
might
well
fit
within
that
standard.
For
example,
piping
or
drainage
from
that
facility
might
lead
directly
to
navigable
water.
If
discharged
oil
may
reach
or
does
reach
navigable
waters,
adjoining
shorelines,
or
protected
resources,
the
distance
which
the
discharged
oil
travels
is
irrelevant.
31
Sheens.
See
the
discussion
of
the
dangers
of
discharged
oil
under
the
discussion
of
the
definition
of
"oil"
in
today's
preamble.

IV­
A­
3
Electrical
equipment
Background:
In
the
preamble
to
the
1991
proposal,
we
noted
that
certain
facilities
may
have
equipment
such
as
electrical
transformers
that
contain
significant
quantities
of
oil
for
equipment
operation
–
not
storage.
We
said
that
operational
oil­
filled
equipment
should
not
be
subject
to
§§
112.8(
c)
or
112.9(
d),
which
address
bulk
storage
containers
at
onshore
facilities.
Consequently,
an
owner
or
operator
of
a
facility
with
equipment
containing
oil
for
ancillary
purposes
need
not
provide
secondary
containment
for
this
equipment
nor
implement
the
other
provisions
of
proposed
§§
112.
8(
c)
or
112.
9(
d).
However,
oil­
filled
equipment
must
meet
other
applicable
SPCC
requirements,
including
the
general
requirements
in
§112.7
and
112.7(
c),
to
provide
appropriate
containment
and
or
diversionary
structures
to
prevent
discharged
oil
from
reaching
navigable
waters.

Comments:
We
should
be
consistent
with
the
part
280
requirements,
and
exclude
from
part
112
electrical
equipment
that
requires
mineral
oil
to
operate.
Otherwise,
we
would
be
imposing
a
substantial
regulatory
burden
on
owners
or
operators.
We
excluded
electrical
equipment
from
part
280,
rationalizing
that
these
types
of
tank
systems
pose
a
relatively
low
level
of
risk
compared
to
other
types
of
storage
tanks.
Electrical
substations
and
other
installations
are
not
facilities
as
defined
in
the
proposed
rule.
Electrical
equipment
does
not
consume
oil,
and
therefore
is
not
covered
under
the
SPCC
program.
(130,
138)

Response:
We
disagree
that
oil­
filled
electrical
equipment,
as
well
as
other
operational
equipment,
is
not
subject
to
the
SPCC
rule.
We
have
amended
§112.1(
b)
to
clarify
that
using
oil,
for
example
operationally,
may
subject
a
facility
to
SPCC
jurisdiction
as
along
as
the
other
applicability
criteria
apply,
for
example,
oil
storage
capacity,
or
location.
Such
a
facility
might
reasonably
be
expected
to
discharge
oil
as
described
in
§112.
1(
b).
Therefore,
the
prevention
of
discharges
from
such
facility
falls
within
the
scope
of
the
statute.
We
also
defined
facility
in
the
final
rule
to
include
equipment
in
which
oil
is
used
or
stored.
32
IV
­
B:
Exemption
of
completely
buried
containers
­
§112.1(
d)(
2)(
i)
and
(d)(
4)

Background:
Under
§112.1(
d)(
2)(
i)
and
(ii)
of
the
current
rule,
a
facility
with
a
completely
buried
storage
capacity
of
42,000
gallons
or
less
of
oil
and
with
an
aboveground
storage
capacity
of
1,320
gallons
or
less
of
oil,
provided
no
single
container
has
a
capacity
in
excess
of
660
gallons,
is
exempted
from
the
requirements
of
part
112.
In
§112.1(
d)(
2)(
i)
of
the
1991
proposal,
we
proposed
to
exclude
the
capacity
of
underground
storage
tanks
(editorially
changed
to
"completely
buried
tanks,"
as
defined
in
§112.2)
subject
to
all
of
the
technical
requirements
of
40
CFR
part
280.
(Subterranean
vaults,
bunkered
tanks,
and
partially
buried
tanks
are
considered
aboveground
storage
containers
for
purposes
of
part
112.
See
the
definition
discussion
in
Category
VI
of
this
document.)
We
also
proposed
in
§112.1(
d)(
4)
to
exclude
from
part
112
applicability,
completely
buried
tanks,
subject
to
the
technical
requirements
of
part
280.

Comments:
Support
for
proposal.
"We
also
support
the
exemption
of
the
underground
storage
tanks
that
are
subject
to
40
CFR
part
280.
This
will
eliminate
duplicate
regulation
of
these
tanks."
(27,35,
53,
66,
67,
71,
75,
82,
92,
95,
102,
103,
106,
107
115,
118,
125,
133,
135,
136,
164,
173,
175,
182,
190,
L24,
L29)

Consistency.
We
should
be
consistent
in
our
approach
to
regulating
ASTs
and
USTs.
For
example,
under
part
280,
UST
systems
that
store
fuel
solely
for
use
by
emergency
power
generators
do
not
have
to
comply
with
the
"release
detection"
requirements
in
part
280.
Therefore,
we
should
"defer
AST
systems
that
store
fuel
solely
for
use
by
emergency
power
generators
from
the
listed
secondary
containment
options."
(69)

Editorial
suggestion.
Supports
the
proposed
exclusion
of
USTs
from
part
112,
but
we
should
include
the
provision
in
§112.1,
rather
than
in
the
§112.2
definitions.
(121)

Equivalency.
"EPA
itself
states
that
the
UST
program
offers
protection
`equivalent'
to
that
provided
by
the
SPCC
program.
That
being
the
case,
EPA
has
every
reason
to
avoid
the
confusion
that
would
result
as
the
regulated
community
implements
a
scheme
under
which
it
is
difficult
to
determine
the
applicability
of
the
regulation."
(35,
57,
71,
173)

Reduced
paperwork.
Supports
proposal
to
exclude
certain
USTs
from
part
112
coverage
and
from
the
SPCC
threshold
calculation,
because
it
would
substantially
decrease
the
amount
of
unnecessary
paperwork
that
an
owner
or
operator
generates
and
that
we
review.
(103)

Opposition
to
proposal.
Opposes
the
§112.1(
d)(
2)(
i)
and
(d)(
4)
exclusions.
(43,
44,
47,
L4,
L5)
33
Confusing.
"...(
T)
he
exemption
of
USTs
regulated
under
40
CFR
280
means
that
a
facility
owner
may
have
some
tanks
that
are
exempt
from
SPCC
requirements
and
some
not.
...
This
could
get
really
confusing!"
(111)

Costs.
We
should
not
exempt
facilities
with
underground
storage
tank
(UST)
installations
whose
total
capacity
exceeds
42,000
gallons,
because
the
rulemaking
docket
contained
no
economic
justification
for
this
and
Congress
enacted
no
law
requiring
the
change.
(43)

Groundwater.
"Exempting
all
combinations
and
sizes
of
USTS
from
the
proposed
Oil
Pollution
regulation
in
an
effort
to
avoid
overlapping
federal
rules
may
appear
attractive
in
a
paperwork
reduction
sense.
But
this
regulatory
approach
does
not
consider
some
basic
characteristics
of
the
natural
resource:
groundwater
eventually
becomes
surface
water.
Hydrologically,
oil
released
into
underground
waters
may
migrate
to
surface
water
within
minutes
or
months.
Certain
classes
of
USTs
could
seriously
damage
the
nation's
ground
and
surface
water
resources
if
an
accident
were
to
occur
in
the
absence
of
emergency
responsive
provisions."
Urges
no
further
action
"until
further
legislative
remedies
are
in
place."
(L4)

UST
rules
insufficient.
UST
regulations
are
insufficient
to
protect
navigable
waters
from
oil
discharges.
The
part
280
requirements
lack
adequate
emergency
response,
training,
contingency
planning,
recordkeeping,
and
spill
prevention
planning
requirements,
diking
of
fuel
transfer
areas;
fuel
transfer
area
operational
procedures,
illumination
of
fuel
transfer
areas;
storm
water
drainage
system
design;
posting
of
vehicle
weight
restrictions
in
areas
where
there
is
underground
piping
and/
or
design
of
underground
piping
to
withstand
vehicular
loadings;
or
a
requirement
for
an
application
of
"good
engineering
practice."
(24,
43,
44,
L4)
"Also,
response
actions
for
underground
storage
tanks
leaks
should
remain
part
of
the
written
SPCC
Plan."
(27)
An
owner
or
operator
of
a
tank
system
subject
to
part
280
does
not
have
to
comply
with
the
part
280
release
detection
requirements.
Under
the
1991
proposal,
these
owners
or
operators
would
not
have
to
prepare
an
SPCC
Plan
or
install
release
detection
systems.
(76)
The
leak
detection
and
tank
installation
requirements
for
buried
tanks
should
be
consistent
with
part
280.
(111)
"The
Agency
should
not
hold
a
position
that
UST
program
regulation
of
those
facilities
would
satisfy
the
spill
prevention
requirements
of
40
CFR
112."
(L5)

Emergency
response.
"Certain
classes
of
USTs
could
seriously
damage
the
nation's
ground
and
surface
water
resources
if
an
accident
were
to
occur
in
the
absence
of
emergency
responsive
provisions."
(L4)

PE
certification.
"...(
T)
he
UST
regulation
does
not
require
the
development
and
certification
of
spill
prevention
plans
as
is
required
under
Oil
Pollution
Act
regulations."
(L4)
34
Applicability.

Piping.
"Under
the
proposed
rule,
it
is
unclear
whether
or
to
what
extent
the
piping
connecting
USTs
and
ASTs
in
such
circumstances
is
regulated
under
the
SPCC
program.
If
such
piping
is
subject
to
the
leak
detection
requirements
for
USTs
under
40
CFR
part
280,
then
ILMA
believes
the
piping
should
remain
exclusively
within
the
jurisdiction
of
the
UST
program
and
should
be
exempted
from
the
SPCC
regulations."
(48)

Partially
buried
tanks
and
bunkered
tanks.
"Bunkered
tanks
and
partially
buried
tanks
should
be
covered
by
the
UST
program
since
ten
percent
or
more
of
the
product
is
below
grade
either
in
the
tank
or
pipeline.
Tanks
under
the
UST
program
should
be
adequately
protected
to
prevent
and
minimize
releases
to
the
environment.
Tanks
not
covered
by
the
UST
program
should
be
considered
aboveground
storage
tanks
(provided
that
they
are
not
permanently
closed)
for
purposes
of
the
SPCC
regulation
and
should
b
subject
to
the
requirements."
(190)

Clarification.
Proposed
§112.1(
d)(
2)(
i)
is
confusing.
Asks
whether
it
is
coverage
by
part
280
that
permits
an
owner
or
operator
to
exclude
the
capacity
of
a
buried
tank
from
the
42,000
gallon
threshold,
or
the
lack
of
such
coverage.
(28,
31,
165,
L15)

Definitions.
"EPA
should
devise
a
regulatory
scheme
under
which
the
same
definition
of
underground
storage
tanks
is
used
in
the
UST
and
SPCC
regulatory
programs...."
(57)

Delegation.
We
should
consider
implementing
a
program
for
ASTs
similar
to
the
UST
program.
The
UST
program,
which
"franchises"
programs
to
the
States,
provides
a
flexible
approach
to
enable
and
encourage
States
to
carry
out
delegated
program
activities.
(111)

"In
compliance
with."
We
should
change
proposed
§112.1(
d)(
2)(
i)
and(
d)(
4)
to
state
that
we
exclude
owners
or
operators
of
USTs
in
compliance
with
the
technical
requirements
of
part
280,
rather
than
excluding
owners
or
operators
of
USTs
subject
to
the
part
280
technical
requirements.
(76)

Outreach.
We
should
design
and
implement
an
outreach
program
based
on
the
UST
program's
outreach
efforts
to
give
owners
or
operators
time
to
learn
about
the
program
and
to
prepare
and
implement
an
SPCC
Plan
before
the
regulatory
compliance
deadlines.
(L6)

Response:
Support
for
proposal.
We
appreciate
commenter
support.
In
response
to
the
commenter
who
said
that
we
should
exclude
USTs
through
a
provision
in
§112.1,
rather
than
through
the
§112.2
definitions,
we
agree.
That
is
exactly
the
action
we
proposed
and
adopted.
35
Regulatory
jurisdiction.
To
eliminate
any
possible
confusion
over
regulatory
jurisdiction,
we
explain
in
today's
preamble
(see
the
above
background
discussion)
which
containers
in
a
facility
are
subject
to
40
CFR
part
280
or
a
State
program
approved
under
40
CFR
part
281,
and
which
are
subject
to
part
112.

Opposition
to
proposal.

Discretionary
authority.
Today's
rule
(see
§112.1(
f)
in
today's
preamble
and
section
2
of
the
1993
Comment
Response
Document)
provides
the
Regional
Administrator
with
the
authority
to
require
any
facility
subject
to
EPA
jurisdiction
under
section
311
of
the
CWA,
regardless
of
threshold
or
other
regulatory
exemption,
to
prepare
and
implement
an
SPCC
Plan
when
necessary
to
further
purposes
of
the
Act.

UST
rules
insufficient.
As
we
noted
in
the
preamble
discussion
of
§112.1(
d)(
1)(
i),
the
UST
program
provides
comparable
environmental
protection
to
the
SPCC
program.
While
not
all
aspects
of
the
programs
are
identical,
the
UST
program
ensures
protection
against
discharges
as
described
in
§112.1(
b),
and
protection
of
the
environment.
Therefore,
dual
regulation
is
unnecessary.
In
response
to
commenters
asserting
that
UST
rules
lack
provisions
concerning
contingency
planning;
emergency
response;
certain
recordkeeping
requirements;
and
other
alleged
deficiencies,
we
disagree.
The
UST
rules
have
numerous
safeguards
addressing
the
commenter's
issues.

Contingency
planning.
While
it
is
true
that
UST
rules
do
not
require
contingency
planning,
spills
and
overfills
of
USTs
resulting
in
a
discharge
to
the
environment
are
much
less
likely
as
a
result
of
those
rules.
An
owner
or
operator
of
an
underground
storage
tank
subject
to
40
CFR
part
280
or
a
State
program
approved
under
40
CFR
part
281
was
required
to
install
spill
and
overfill
prevention
equipment
no
later
than
December
22,
1998.
40
CFR
280.20
and
280.21.
The
use
of
this
equipment
will
greatly
reduce
the
likelihood
of
both
small
and
large
releases
or
discharges
of
petroleum
to
the
environment
through
surface
spills
or
overfilling
underground
storage
tanks.
In
addition,
the
UST
rules
place
a
general
responsibility
on
the
owner
or
operator
to
ensure
that
discharges
due
to
spilling
and
overfilling
do
not
occur.
See
40
CFR
280.30.

Emergency
response
and
release
reporting.
The
UST
rules
also
have
several
requirements
related
to
emergency
response
and
release
or
discharge
reporting.
The
UST
rules
generally
require
that
releases
of
regulated
substances
be
reported
to
the
implementing
agency
within
24
hours.
As
part
of
the
initial
response
requirements
(found
at
40
CFR
280.61),
an
owner
or
operator
must
take
immediate
action
to
prevent
further
release
of
the
regulated
substance
and
must
identify
and
mitigate
fire,
explosion,
and
vapor
hazards.

Reporting
and
recordkeeping.
In
addition
to
the
reporting
requirements
mentioned
above,
there
are
numerous
reporting
and
recordkeeping
36
requirements
in
the
rules
governing
underground
storage
tanks.
Among
these
are:
corrective
action
plans;
documentation
of
corrosion
protection
equipment;
documentation
of
UST
system
repairs;
and,
information
concerning
recent
compliance
with
release
detection
requirements.
Thus,
the
UST
rules
have
significant
reporting
and
recordkeeping
requirements,
including
specific
requirements
related
to
spills
and
overfills.

Transportation
rules.
In
addition
to
the
EPA
UST
rules,
the
U.
S.
Department
of
Transportation
has
hazardous
material
regulations
related
to
driver
training,
emergency
preparation,
and
incident
reporting
and
emergency
response.
Training
regulations,
for
example,
can
be
found
at
49
CFR
part
172,
and
loading
and
unloading
regulations
can
be
found
at
49
CFR
177.834
and
49
CFR
177.837.
These
regulations
apply,
for
example,
to
truck
drivers
delivering
gasoline
or
diesel
fuel
to
gas
stations
with
underground
storage
tanks.

Piping,
ancillary
equipment,
and
containment
systems.
EPA
has
modified
the
scope
of
the
proposed
exemption
for
completely
buried
tanks
(which
are
excluded
from
the
scope
of
the
SPCC
rule
if
they
are
subject
to
all
of
the
technical
requirements
of
40
CFR
part
280
or
a
State
program
approved
under
40
CFR
part
281)
by
clarifying
that
the
exemption
includes
the
connected
underground
piping,
underground
ancillary
equipment,
and
containment
systems,
in
addition
to
the
tank
itself.
This
modification
is
consistent
with
the
definition
of
underground
storage
tank
system
found
at
40
CFR
280.12.
In
addition,
this
clarification
is
responsive
to
the
comment
which
asked
that
the
piping
be
included
in
the
exemption.

Clarification.
We
disagree
that
§112.1(
d)(
2)(
i)
is
confusing.
If
a
completely
buried
tank
is
subject
to
all
of
the
technical
requirements
of
40
CFR
part
280
or
a
State
program
approved
under
40
CFR
part
281,
it
is
exempt
from
the
SPCC
rule.
Otherwise,
it
may
be
subject
to
the
rule.

Delegation.
We
have
no
authority
under
the
Clean
Water
Act
to
delegate
our
program
to
the
States,
unlike
the
UST
program.
However,
States
may
enact
their
own
prevention
programs.
The
Act
does
not
preempt
States
from
doing
so.

"In
compliance
with."
We
disagree
that
we
should
change
§112.1(
d)(
2)(
i)
and(
d)(
4)
to
exclude
an
owner
or
operator
of
a
facility
with
completely
buried
tanks
in
compliance
with
the
technical
requirements
of
part
280
(or
a
State
program
approved
under
part
281),
rather
than
subject
to
part
280
(or
part
281)
technical
requirements.
Regulatory
jurisdiction
would
be
chaotic
under
a
scheme
measuring
compliance.
A
facility
might
be
in
compliance
one
day
and
not
the
next,
subjecting
the
facility
to
dual
regulation.

Outreach.
We
agree
that
outreach
is
necessary
and
will
conduct
extensive
outreach
efforts
after
publication
of
this
rule.
37
Partially
buried
tanks
and
bunkered
tanks.
We
disagree
that
partially
buried
tanks
and
bunkered
tanks
should
be
considered
completely
buried
tanks,
and
therefore
excluded
from
SPCC
provisions.
Such
tanks
may
suffer
damage
caused
by
differential
corrosion
of
buried
and
non­
buried
surfaces
greater
than
completely
buried
tanks,
which
could
cause
a
discharge
as
described
in
§112.1(
b).
Such
tanks
are
also
not
subject
to
secondary
containment
requirements
under
part
280
or
a
State
program
approved
under
40
CFR
part
281.
There
may
also
be
accidents
during
loading
or
unloading
operations,
or
overfills
resulting
in
a
discharge
to
navigable
waters
and
adjoining
shorelines.
Furthermore,
a
failure
of
such
a
tank
(caused
by
accident
or
vandalism)
would
be
more
likely
to
cause
a
discharge
as
described
in
§112.1(
b).
Therefore,
these
tanks
must
be
regulated
under
the
SPCC
program.

We
will,
however,
accept
UST
program
forms,
e.
g.,
the
Notification
for
Underground
Storage
Tanks,
EPA
Form
7530­
1,
or
an
approved
State
program
equivalent,
insofar
as
such
form
contains
information
relevant
to
the
SPCC
program.
For
example,
the
UST
form
contains
information
regarding
corrosion
protection
for
steel
tanks
and
steel
piping
(item
12)
which
would
be
relevant
for
SPCC
purposes.
Other
items
on
the
form
may
also
be
relevant
for
SPCC
purposes.

Effect
on
Facility
Response
Plan
facilities.
The
exemption
for
completely
buried
tanks
subject
to
all
the
technical
requirements
of
40
CFR
part
280
or
a
State
program
approved
under
40
CFR
part
281
applies
to
the
calculation
of
storage
capacity
both
for
SPCC
purposes
and
for
Facility
Response
Plan
(FRP)
purposes
because
the
exemption
applies
to
all
of
part
112.
Therefore,
a
few
FRP
facilities
with
large
capacity
completely
buried
tanks
subject
to
40
CFR
part
280
or
a
State
program
approved
under
40
CFR
part
281
might
no
longer
be
required
to
have
FRPs.
Calculations
for
planning
levels
for
worst
case
discharges
will
also
be
affected.
However,
the
Regional
Administrator
retains
authority
to
require
the
owner
or
operator
of
any
nontransportation
related
onshore
facility
to
prepare
and
submit
a
FRP
after
considering
the
factors
listed
in
§112.20(
f)(
2).
See
§112.20(
b)(
1).

IV­
B­
1
Completely
buried
tanks
regulated
under
State
programs
Comments:
"Although
certain
USTs
such
as
heating
oil
tanks
are
deferred
or
exempted,
because
of
concern
for
the
environment
and/
or
more
stringent
state
regulations,
these
USTs
may
incorporate
all
of
the
technical
requirements
of
the
fully
regulated
USTs.
If
owners
having
exempted
or
deferred
USTs
take
the
necessary
action
to
comply
with
the
UST
technical
requirements,
these
USTs
should
likewise
be
excluded
from
40
CFR
112
requirements."
(79)

Response:
We
agree,
and
have
revised
the
rule
accordingly.
In
§112.1(
d)(
4)
of
the
final
rule,
we
exempt
from
part
112
requirements
(except
the
facility
diagram)
completely
buried
tanks
subject
to
all
of
the
technical
requirements
of
State
programs
approved
under
part
281.
When
we
proposed
the
part
280
exemption
in
1991,
few
if
any
States
had
an
approved
program.
In
40
CFR
part
281
(published
on
September
23,
1988
at
53
FR
37212),
EPA
established
regulations
whereby
a
State
could
receive
38
EPA
approval
for
its
State
program
to
operate
in
lieu
of
the
Federal
program.
In
order
to
obtain
EPA
program
approval
under
part
281,
a
State
program
must
demonstrate
that
its
requirements
are
no
less
stringent
than
the
corresponding
Federal
regulations
set
forth
in
part
280,
and
that
it
provides
adequate
enforcement
of
these
requirements.
Thus,
we
have
decided
to
exempt
also
the
storage
capacity
of
USTs
subject
to
all
of
the
technical
requirements
of
State
UST
programs
which
EPA
has
approved.
By
January
2000,
EPA
had
approved
27
State
programs,
plus
programs
in
the
District
of
Columbia
and
Puerto
Rico.
The
rationale
for
exempting
the
storage
capacity
of
these
facilities
from
the
SPCC
regime
is
because
40
CFR
part
280
and
the
approved
State
programs
under
40
CFR
part
281
provide
comparable
environmental
protection
for
the
purpose
of
preventing
discharges
as
described
in
§112.1(
b).

IV­
B­
2
Editorial
changes
and
clarifications
Comments:
Piping,
ancillary
equipment,
and
containment
systems.
It
is
unclear
how
part
112
addresses
piping
that
connects
USTs
to
aboveground
storage
tanks
(ASTs);
we
should
exclude
from
part
112
regulation,
piping
subject
to
part
280
leak
detection
requirements.
(48)
Proposed
§112.1(
d)
is
unclear.
(111)

Editorial
reference.
In
proposed
§112.1(
d),
our
reference
to
the
"first
sentence
of
§112.7(
a)(
3),"
appears
to
be
incorrect.
(16)

Response:
Piping,
ancillary
equipment,
and
containment
systems.
EPA
has
modified
the
scope
of
the
proposed
exemption
for
completely
buried
tanks
(which
are
excluded
from
the
scope
of
the
SPCC
rule
if
they
are
subject
to
all
of
the
technical
requirements
of
40
CFR
part
280
or
a
State
program
approved
under
40
CFR
part
281)
by
clarifying
that
the
exemption
includes
the
connected
underground
piping,
underground
ancillary
equipment,
and
containment
systems,
in
addition
to
the
tank
itself.
This
modification
is
consistent
with
the
definition
of
underground
storage
tank
system
found
at
40
CFR
280.12.
In
addition,
this
clarification
is
responsive
to
the
comment
which
asked
that
the
piping
be
included
in
the
exemption.

Editorial
reference.
We
disagree
that
our
reference
to
§112.7(
a)(
3)
in
the
proposed
introductory
paragraph
of
§112.1(
d)
is
incorrect.
However,
we
have
removed
the
§112.7(
a)(
3)
reference
in
introductory
paragraph
of
§112.1(
d)
and
placed
it
instead
in
§112.(
d)(
4).
We
thus
clarify
that
regardless
of
whether
a
completely
buried
tank
is
excluded
from
part
112,
the
owner
or
operator
must
mark
such
tank
on
the
facility
diagram,
if
the
facility
is
otherwise
subject
to
part
112.
(See
Category
X­
C
of
this
document
for
further
discussion
on
facility
diagrams.)

IV
­
C:
Exemption
of
permanently
closed
containers
­
§112.1(
b)(
2)
and
(d)(
2)(
ii)

See
also
section
V­
11,
definition
of
"permanently
closed.")

Background:
Section
112.1(
b)
establishes
the
general
applicability
of
part
112.
In
1991,
in
§112.1(
b)(
2),
we
proposed
that
part
112
would
apply
to
a
facility
with
a
39
container
used
for
standby
storage,
seasonal
storage,
or
temporary
storage,
or
not
otherwise
permanently
closed
(as
defined
in
§112.2).

Current
§112.
1(
d)
describes
the
facilities
excluded
from
part
112.
In
1991,
in
§112.1(
d)(
2)(
i)
and
(ii),
we
proposed
that
the
facility
threshold
storage
capacity
would
not
include
the
capacity
of
underground
storage
tanks
that
are
permanently
closed
(as
defined
in
§112.2).

Comments:
Support
for
proposal.
"We
agree
that
storage
tanks
which
meet
the
criteria
for
being
permanently
closed
...
should
be
exempt
from
40
CFR
part
112.
We
believe
that
these
tanks,
when
properly
and
permanently
closed,
pose
no
danger
to
the
public
health
or
the
environment."
(23,
36,
72,
75,
86,
90,
95,
102,
103,
118,
175,
190,
L12,
L24,
L29)

Decommission.
"Because
`recommissioning'
of
a
tank
requires
that
the
Plan
be
amended,
the
need
for
the
definition
would
not
appear
to
be
necessary
if
the
wording
was
changed
to
decommission
instead
of
permanently
closed.
This
would
provide
the
facility
operator
more
flexibility
without
a
reduction
in
the
protection
afforded."
(76)

Non­
oil
storage.
"Any
regulations
should
recognize
that
a
tank
does
not
have
to
be
empty
of
all
products,
only
oil
products,
to
be
considered
`permanently
closed'
from
the
standpoint
of
this
regulation."
(51)

Tanks,
not
facilities.
We
should
exclude
from
SPCC
Plan
requirements
permanently
closed
tanks
"rather
than
facilities
where
all
tanks
are
closed."
(L24)

Temporary
closure.
"Pennzoil
has
several
oil
production
sites
where
we
have
ceased
production,
but
not
permanently
closed
the
site,
pending
more
favorable
economics
to
restart
production.
Under
this
proposal,
it
appears
that
we
would
have
to
either
permanently
close
the
unused
tanks
(at
a
cost
of
$450
to
$1500
per
tank)
and
then
pay
to
reopen
the
tanks
or
prepare
SPCC
plans
for
empty
tanks.
Both
of
these
alternatives
seem
unnecessary
to
us.
...
Pennzoil
suggests
that
instead
the
capacity
of
these
tanks
not
be
included,
provided
the
operator
can
show
that
the
tanks
have
been
shut­
in
and
all
fluid
removed
down
to
the
pipeline
connection."
(71,107)

Emergency
response.
"...(
T)
he
requirements
for
advance
notification,
and
various
construction
and
operating
procedures
are
neither
appropriate
nor
practical
for
temporary
storage
during
a
spill
response
effort."
Therefore,
suggests
we
"exempt
from
the
Proposed
Rule
temporary
storage
facilities
used
in
an
emergency
response."
(60,
75,
103)

Frac
tanks.
"...(
U)
nless
language
were
added
to
exclude
fractionization
tanks
from
the
SPCC
program,
each
time
a
frac
tank
is
used
or
moved
to
a
new
location,
a
modification
to
the
facility­
specific
SPCC
plan
would
be
required
per
112.5(
a).
Frac
tanks
are
often
used
to
store
oil
for
short
periods
of
time
while
maintenance
or
workover
operations
are
underway.
The
use
of
frac
tanks
is
of
40
very
short
duration
and
does
not
necessarily
increase
the
potential
for
a
discharge."
(167)

Mining
operations.
"Once
again,
an
interpretation
covering
drums
for
temporary
storage
poses
severe
practical
problems
for
PDC,
where
one
or
two
oil
drums
might
be
temporarily
located
at
remote
portions
of
a
large
mining
operation,
and
it
is
impractical
to
maintain
an
up­
to­
date
SPCC
plan
that
addresses
such
drum
storage
and
use."
(L24)

Sludge.
"EPA
should
allow
tanks
which
are
`temporarily
closed'
(i.
e.,
have
no
free
product,
but
contain
an
oil
sludge)
to
be
exempt
from
the
operational
and
design
requirements
of
these
regulations."
(L2)

Who
determines
permanent
closure.
"Within
its
definition
of
`permanently
closed'
(relative
to
tanks)
the
proposed
rule
would
designate
a
number
of
conditions
that
must
be
met
by
the
facility.
DuPont
believes
that
the
imposition
of
such
conditions
is
unnecessary
and
the
designation
of
`permanently
closed'
should
be
left
to
the
facility.
Facilities
are
liable
for
the
release
of
oil
and
must
keep
plans
up
to
date
for
any
component
of
the
facility
which
could
release
oil."
(155)

Response:
Support
for
proposal.
We
appreciate
commenter
support.

Decommission.
We
disagree
that
the
need
for
the
definition
is
unnecessary
if
the
wording
were
changed
from
permanently
closed
to
decommission.
A
tank
that
is
"decommissioned"
might
not
meet
the
standards
for
permanent
closure
in
the
rule.

Non­
oil
storage.
Containers
storing
products
which
are
not
oil
are
not
subject
to
the
SPCC
rule.

Temporary
closure.
If
a
tank
is
not
permanently
closed,
it
is
still
available
for
storage
and
the
possibility
of
a
discharge
as
described
in
§112.
1(
b),
remains.
A
tank
closed
for
a
temporary
period
of
time
may
contain
oil
mixed
with
sludge
or
residues
of
product
which
could
be
discharged.
A
discharge
from
such
facility
could
cause
severe
environmental
damage.
Therefore,
it
must
remain
subject
to
the
rule.
Nor
does
a
short
time
period
of
storage
eliminate
the
possibility
of
such
a
discharge.

We
agree
that
we
should
exclude
permanently
closed
containers
from
Plan
requirements,
and
have
revised
§112.1(
b)(
3),
(d)(
2)(
i),
and
(d)(
2)(
ii)
to
provide
that
permanently
closed
containers
are
excluded
from
part
112
requirements.
A
facility
that
contains
only
permanently
closed
containers
is
no
longer
subject
to
SPCC
requirements.

Who
determines
permanent
closure.
We
disagree
that
we
should
allow
the
owner
or
operator
to
designate
which
containers
are
permanently
closed.
We
believe
that
a
definition
is
necessary
based
on
objective
requirements
to
avoid
confusion
as
to
when
41
we
consider
a
container
permanently
closed.
Therefore,
we
have
promulgated
a
definition
of
permanently
closed.
See
§112.2.

IV
­
D:
Exemption
of
Minerals
Management
Service
(MMS)
facilities
­
§112.1(
d)(
3)

Background:
In
§112.1(
d)(
3)
of
the
1991
proposal,
we
proposed
to
exempt
from
the
SPCC
regulation
facilities
subject
to
regulation
under
the
United
States
Department
of
Interior's
(DOI's)
Minerals
Management
Service
(MMS)
Operating
Orders,
notices,
and
regulations.
In
general,
these
facilities
are
offshore
oil
production
or
exploration
facilities.
We
proposed
this
exemption
to
avoid
redundancy
in
regulation.
Under
section
2(
b)(
1)
of
Executive
Order
(EO)
12777,
the
President
delegated
authority
to
various
Executive
Branch
agencies
to
regulate
entities
covered
under
the
CWA.
See
56
FR
54747,
October
22,
1991.
The
EO
gave
EPA
the
authority
to
regulate
nontransportation
related
onshore
oil
facilities.
The
President
delegated
similar
authority
over
transportation­
related
onshore
facilities,
deepwater
ports,
and
vessels
to
the
United
States
Department
of
Transportation
(DOT);
and
authority
over
other
offshore
facilities,
including
associated
pipelines,
to
DOI.
Before
EO
12777,
MMS
regulated
facilities
on
the
Outer
Continental
Shelf
(OCS)
(i.
e.,
three
miles
or
more
beyond
the
coast
line).
EO
12777
gave
DOI
authority
for
spill
prevention,
control,
and
countermeasure
planning
for
all
offshore
facilities,
including
some
facilities
traditionally
subject
to
our
jurisdiction.

In
a
Memorandum
of
Understanding
(MOU)
between
DOI,
DOT,
and
EPA,
effective
on
February
3,
1994,
DOI
redelegated
to
EPA
the
responsibility
for
regulating
nontransportation
related
offshore
facilities
located
landward
of
the
coast
line.
This
MOU
is
found
in
Appendix
B
of
the
current
rule.
As
a
result
of
this
redelegation,
offshore
facilities
landward
of
the
coast
line
remain
subject
to
our
jurisdiction.
Offshore
facilities
seaward
of
the
coast
line
are
subject
to
DOI
jurisdiction,
except
for
deepwater
ports
and
associated
pipelines
delegated
to
DOT.

Comments:
Support
for
proposal.
"The
proposed
revision
regarding
SPCC
plans
in
the
OCS
is
welcome.
Considerable
confusion
regarding
the
need
of
both
an
SPCC
plan
and
a
MMS
Spill
Contingency
plan
exists."
"The
existing
provisions
of
the
MMS
regarding
oil
spill
prevention
and
contingency
planning
are
comprehensive
and
provide
a
level
of
protection
equivalent
to
that
envisioned
by
EPA's
proposed
rules."
(67,
75,
97,
110,
113,
133,
173,
L12)

Opposition
to
proposal.
"...(
W)
e
are
concerned
with
MMS'
`historic
treatment
of
identified
violations.
'
MMS
failed
to
issue
a
single
civil
penalty
since
1982.
The
EPA,
with
its
mechanism
and
authority
to
impose
civil
penalties,
should
not
exempt
offshore
oil
exploration
and
production
from
the
requirements
of
the
proposed
regulation.
Such
action
would
surely
result
in
better
protection
of
the
environment."
(123,
142,
L13)

"More
stringent."
The
more
stringent
of
EPA
or
MMS
regulations
should
take
precedence.
(L13)
42
Clarification.
Asks
which
agency
–
EPA,
DOI,
or
DOT
–
now
has
authority
under
section
311(
j)
of
the
CWA
over
"a
portable
drilling
unit
operating
in
the
bed
of
an
intermittent
stream
in
New
Mexico."
(121)

Response:
Support
for
proposal.
We
appreciate
commenter
support.
We
have
retained
our
original
proposal,
except
for
an
editorial
revision,
because
we
believe
that
MMS
will
provide
equivalent
environmental
protection
for
the
facilities
under
its
jurisdiction.
MMS
regulations
require
adequate
spill
prevention,
control,
and
countermeasures
that
are
directed
more
specifically
to
the
facilities
subject
to
MMS
requirements.

In
response
to
the
commenter
concerned
about
MMS'
enforcement
record,
as
we
noted
in
the
1991
Preamble,
we
believe
that,
based
on
an
analysis
of
the
MMS
regulations
(formerly
known
as
Operating
Orders),
MMS
requires
adequate
spill
prevention,
control,
and
countermeasure
practices.

"More
stringent."
We
disagree
that
the
more
stringent
of
rules
should
take
precedence
unless
the
facility
is
a
complex.
If
the
facility
is
not
a
complex,
then
the
rules
of
the
agency
with
jurisdiction
apply.

Clarification.
To
determine
which
Federal
agency
has
authority
over
a
particular
type
of
facility,
we
refer
the
reader
to
Appendix
B
of
part
112.
A
portable
drilling
unit
operating
in
the
bed
of
an
intermittent
stream
would
be
under
EPA
jurisdiction,
assuming
it
met
the
regulatory
threshold
and
that
there
is
a
reasonable
possibility
of
a
discharge
as
described
in
§112.
1(
b)
from
the
facility.
The
MOU
between
DOI,
DOT,
and
EPA
in
Appendix
B
provides
that
we
have
authority
to
regulate
non­
transportation­
related
offshore
facilities
located
landward
of
the
coast
line.
The
MOU
in
Appendix
A
defines
non­
transportation­
related
and
transportation­
related
onshore
and
offshore
facilities.
It
defines
a
mobile
oil
well
drilling
facility
as
non­
transportation­
related
when
fixed
in
position
for
drilling
operations.
See
35
FR
11677,
July
22,
1970.

IV
­
E:
Regulatory
threshold
­
§112.1(
d)(
2)

Background:
Section
112.1(
d)(
2)
contains
the
regulatory
threshold
provisions
of
part
112.

Comments:
Regulatory
threshold.
The
threshold
capacity
criteria
should
be
higher.
The
provision
would
regulate
a
universe
of
small
facilities
that
pose
no
significant
risk
to
navigable
waters.
(41,
125,
130,
189)
Re
proposed
§112.1(
d)(
2)(
i),
"We
do
not
believe
EPA
intended
to
exempt
solely
those
facilities
meeting
both
of
the
above
criteria.
Instead,
it
would
appear
EPA
intended
this
to
be
a
`small
entity'
exemption."
Suggests
replacing
the
word
"both"
with
"either"
in
introductory
language
to
paragraph
(2).
(33)
Our
"all­
encompassing"
approach
would
subject
tens
of
thousands
of
aboveground
tanks
to
the
SPCC
rule
­­
from
small
production
tanks
to
large
storage
facilities
at
a
refinery
or
a
terminal
facility.
(71,
78)
43
Effectiveness
and
enforcement.
"PEO
feels
that
the
inclusion
of
these
excessively
small
facilities
dilute
the
effectiveness
of
the
program
and
the
enforcement
of
larger
facilities
which
pose
a
genuine
threat."
(41)

Response:
Regulatory
threshold.
We
agree
that
the
threshold
should
be
higher.
We
have
decided
to
raise
the
current
regulatory
threshold,
as
discussed
in
the
1997
preamble,
to
an
aggregate
threshold
of
over
1,
320
gallons.
We
believe
that
raising
the
regulatory
threshold
is
justified
because
our
Survey
of
Oil
Storage
Facilities
(published
in
July
1996,
and
available
on
our
web
site
at
www.
epa.
gov/
oilspill)
points
to
the
conclusion
that
several
facility
characteristics
can
affect
the
chances
of
a
discharge.
First,
the
Survey
showed
that
as
the
total
storage
capacity
increases,
so
does
the
propensity
to
discharge,
the
severity
of
the
discharge,
and
the
costs
of
cleanup.
Likewise,
the
Survey
also
pointed
out
that
as
the
number
of
tanks
increases,
so
does
the
propensity
to
discharge,
the
severity
of
the
discharge,
and
the
costs
of
cleanup.
Finally,
the
Survey
showed
that
as
annual
throughput
increases,
so
does
the
propensity
to
discharge,
the
severity
of
the
discharge,
and,
to
a
lesser
extent,
the
costs
of
the
cleanup.

The
threshold
change
will
have
several
benefits.
The
threshold
increase
will
result
in
a
substantial
reduction
in
information
collection.
Some
smaller
facilities
will
no
longer
have
to
bear
the
costs
of
an
SPCC
Plan.
EPA
will
be
better
able
to
focus
its
regulatory
oversight
on
facilities
that
pose
a
greater
likelihood
of
a
discharge
as
described
in
§112.1(
b),
and
a
greater
potential
for
injury
to
the
environment
if
a
discharge
as
described
in
§112.1(
b)
results.

We
raise
the
regulatory
threshold
realizing
that
discharges
as
described
in
§112.1(
b)
from
small
facilities
may
be
harmful,
depending
on
the
surrounding
environment.
Among
the
factors
remaining
to
mitigate
any
potential
disasters
are
that
small
facilities
no
longer
required
to
have
SPCC
Plans
are
still
liable
for
cleanup
costs
and
damages
from
discharges
as
described
in
§112.
1(
b).
We
encourage
those
facilities
exempted
from
today's
rule
to
maintain
SPCC
Plans.
Likewise,
we
encourage
facilities
becoming
operable
in
the
future
with
storage
or
use
capacity
below
the
regulatory
threshold
which
are
exempted
from
the
rule
to
develop
Plans.
We
believe
that
SPCC
Plans
have
utility
and
benefit
for
both
the
facility
and
the
environment.

While
we
believe
that
the
Federal
oil
program
is
best
focused
on
larger
risks,
State,
local,
or
tribal
governments
may
still
decide
that
smaller
facilities
warrant
regulation
under
their
own
authorities.
In
accord
with
this
philosophy,
we
note
that
this
Federal
exemption
may
not
relieve
all
exempted
facilities
from
Plan
requirements
because
some
States,
local,
or
tribal
governments
may
still
require
such
facilities
to
have
Plans.
While
we
are
aware
that
some
States,
local,
or
tribal
governments
have
laws
or
policies
allowing
them
to
set
requirements
no
more
stringent
than
Federal
requirements,
we
encourage
States,
local,
or
tribal
governments
to
maintain
or
lower
regulatory
thresholds
to
include
facilities
no
longer
covered
by
Federal
rules
where
their
own
laws
or
policies
allow.
We
believe
CWA
section
311(
o)
authorizes
States
to
44
establish
their
own
oil
spill
prevention
programs
which
can
be
more
stringent
than
EPA's
program.

When
a
particular
facility
that
is
below
today's
threshold
becomes
a
hazard
to
the
environment
because
of
its
practices,
or
when
needed
for
other
reasons
to
carry
out
the
Clean
Water
Act,
the
Regional
Administrator
may,
under
a
new
rule
provision,
require
that
facility
to
prepare
and
implement
an
SPCC
Plan.
See
§112.
1(
f).
This
provision
acts
as
a
safeguard
to
an
environmental
threat
from
any
exempted
facility.

IV­
E(
1)­
1
Alternative
thresholds
and
criteria
Comments:
Alternatives
suggested.
We
should
increase
the
capacity
criterion
to
a
number
that
would
better
reflect
facilities
that
pose
a
significant
risk.
(41,
49)

100
gallons.
"If
EPA
insists
on
promulgating
the
proposed
regulations,
then
there
is
no
justification
for
excluding
residential
fuel
oil
storage
tanks.
...
A
threshold
of
100
gallons
should
be
established
to
include
all
tanks
which
threaten
the
environment."
(110)

2,000
gallons.
2,000
gallons
or
less,
provided
no
single
container
has
more
than
1,100
gallons.
(178)

6,000
gallons.
6,000
gallons
or
less
of
aboveground
storage
capacity,
provided
tanks
have
secondary
containment
and
overfill
protection
(79)

10,000
gallons.
10,000
gallons
or
less
of
aggregate
storage
capacity,
provided
tanks
have
adequate
secondary
containment
(L17);
The
regulation
should
apply
only
to
facilities
with
capacity
greater
than
10,
000
gallons,
based
on
individual
unit
size
rather
than
accumulated
volume.
(L20)

30,000
gallons.
30,000
gallons
or
less,
provided
no
single
container
has
more
than
15,000
gallons
(82);
10,000
gallons
or
less
of
aggregate
storage
capacity
(125,
130,170,
189,
and
L18).

42,000
gallons.
(23,
58,
65,
78,
80,
82,
101,
103,
109,
116,
140,
164,
175,
183,
and
L6)
42,000
gallons
or
less,
provided
no
single
container
has
capacity
in
excess
of
10,000
gallons.
(70)
Suggests
different
storage
capacity
levels,
claiming
that
we
chose
42,000
gallons
arbitrarily.
(42,
102,
143,
155,
182,
190)
In
choosing
the
threshold
level,
we
should
consider
a
facility's
proximity
to
navigable
water
or
environmentally
sensitive
areas.
This
commenter
also
stated
that
we
should
consider
a
facility's
use
of
good
engineering
practice
in
revising
the
regulation.
(159)

50,000
gallons
­
underground
storage.
"Many
of
our
service
stations
have
storage
tanks
for
gasoline
and
diesel
fuel
of
12,000
gallons
a
piece.
If
all
four
products
are
provided
at
a
station
­
as
most
are
–
our
service
stations
will
come
45
under
the
requirements
for
SPCC
Plans.
We
do
not
believe
that
this
is
intended,
and
would
request
that
the
gallonage
requirement
be
increased
to
50,000,
not
42,000
gallons."
(177)

Animal
fats,
vegetable
oils.
"Arvin
is
of
the
opinion
that
non­
petroleum
based
oils
such
as
animal
and
vegetable
fats
and
oils
should
be
exempt
from
all
oil
40
CFR
112
requirements."
"The
statutory
history
of
the
spill
control
program,
as
well
as
the
content
of
the
proposed
regulations,
make
it
clear
that
this
program
was
conceived
and
designed
to
prevent
and
manage
spills
involving
petroleum­
based
oils.
...
We
therefore
urge
that
the
final
regulations
make
clear
that
mandatory
requirements
are
not
applicable
to
facilities
producing
or
storing
vegetable
oils."
(56,
137,
162)

Appalachian
producers.
The
proposed
requirements
would
be
detrimental
to
Appalachian
Producers,
and
we
should
exempt
Appalachian
Producers
from
any
further
requirements.
(101)

Electrical
equipment.
"The
Agency
should
change
the
aboveground
storage
capacity
criterion
to
limit
the
applicability
of
the
SPCC
requirements
to
facilities
with
one
or
more
aboveground
oil­
containing
units
with
a
capacity
of
more
than
10,000
gallons
and
to
limit
the
applicability
of
the
SPCC
requirements
at
such
facilities
to
aboveground
tanks
or
containers
with
a
capacity
in
excess
of
660
gallons
and
electrical
equipment
with
aboveground
capacity
in
excess
of
10,000
gallons.
To
the
extent
that
electrical
equipment
is
not
otherwise
excluded
from
regulation
under
the
SPCC
program,
the
Agency
should
conditionally
exclude
all
such
equipment
with
a
capacity
of
42,000
gallons
or
less
from
regulation
unless
the
unit
of
equipment
has
experienced
one
or
more
spill
events."
(125)

Farms.
"Placing
unreasonable
and
expensive
restrictions
on
on­
farm
storage
poses
substantial
risk
to
the
farmer's
ability
to
continue
mechanized
farming
operations.
We
have
not
seen
any
big
rush
of
city
folks
clamoring
to
do
hand
labor
in
the
fields
of
this
nation.
Therefore,
we
request
a
reasonably
crafted
farm
exemption
from
the
aboveground
tank
rules,
based
on
tank
size
and
risk,
such
as
is
contained
in
the
current
underground
storage
tank
regulations."
(73,
106,
L23)

Floating
fuel
tanks.
"It
would
be
extremely
helpful
...
if
the
rule
specifically
addressed
floating
fuel
storage,
and
the
subjects
of
tank
testing
and
diking
and/
or
containment."
(151)

Largest
unit.
The
risk
posed
by
a
facility
is
more
accurately
measured
by
the
size
of
the
largest
individual
unit
at
the
facility
rather
than
the
facility's
aggregate
storage
capacity.
The
failure
of
one
unit
is
extremely
unlikely
to
cause
failure
of
another
unit
because
small
tanks
are
rarely
interconnected.
(125)

No
threshold.
We
should
focus
on
setting
applicability
criteria
by
tank
size,
rather
than
facility
storage
capacity.
(67)
We
should
omit
the
capacity
criterion
for
total
storage
capacity
at
a
facility.
(170,
189)
46
Oil­
filled
equipment,
test
tanks.
We
should
exempt
test
tanks
and
certain
oil­
filled
equipment
from
part
112
because
test
tanks
do
not
store
oil
in
bulk,
and
are
not
intended
to
be
oil­
filled.
Test
tanks
could
not
"reasonably
be
expected
to
discharge
oil
in
quantities
that
may
be
harmful."
(60)

Oil­
water
separators.
Part
112
should
include
facilities
that
have
oil­
water
separators
connected
to
sanitary
or
storm
water
sewers
or
drains.
Oil­
water
separators
are
not
subject
to
part
280
regulations,
because
they
are
"flow­
through
process
tanks."
(43)

Stripper
oil
and
gas
facilities.
We
should
exempt
stripper
oil
and
gas
well
facilities
from
any
new
regulatory
program.
(113)

Treatment
tanks.
We
should
exclude
facility
storage
and
treatment
tanks
associated
with
"non­
contact
cooling
water
systems,"
or
"storm
water
retention
and
treatment
systems."
Although
the
tanks
are
designed
to
remove
spilled
oil
from
manufacturing
operations
and
parking
lot
runoff,
the
tanks
contain
insignificant
concentrations
of
oil
in
the
water.
(90)

Vaulted
tanks.
"We
would
ask
that
the
proposed
rule
be
amended
to
either
exempt
vaulted
tanks
under
3000
gallons,
or
tanks
located
inside
a
facility
with
adequate
secondary
containment,
or
reduce
the
requirements
commensurate
with
the
risk,
i.
e.,
the
size
and
location
of
the
tank.
...
We
request
that
vaulted
tanks
or
tanks
with
other
engineering
controls
designed
to
contain
product
released
from
failure
or
overfill,
or
which
meet
the
technical
requirements
of
40
CFR
part
280,
be
exempted
from
these
regulations.
We
base
this
request
on
the
fact
that
we
employ
containment
and
controls
designed
to
prevent
our
stored
product
from
reaching
either
soil
or
water.
We
provide
for
containment
and
notification
upon
product
release."
(1,
37,
49,
50,
65,
67,
72,
85,
133,
144)

Volume,
not
capacity.
"The
42,000
gallon
capacity
criteria
is
good,
but
CMI
suggests
that
a
further
delineation
separate
large
and
small
facilities.
For
example,
the
amount
of
oil
actually
stored
in
a
tank.
Can
manufacturers
have
large
tanks,
but
the
amount
of
oil
varies
greatly,
normally
only
from
10
to
50
percent
oil
are
contained
in
the
tank."
(62)
We
should
change
the
aboveground
storage
capacity
threshold
calculation
to
an
aboveground
oil
storage
volume
calculation,
so
that
an
owner
or
operator
would
count
the
amount
of
oil
in
the
storage
container.
(35,
167)
We
should
change
this
threshold
calculation
to
a
working
capacity
calculation,
so
that
an
owner
or
operator
would
only
count
the
amount
of
tank
capacity
actually
used
for
storage.
(31,
86,
and
160)

Response:
As
explained
above
(see
section
V­
E
of
this
document),
we
have
raised
the
regulatory
threshold
for
aboveground
storage
capacity
to
over
1,320
gallons.

All
containers.
In
response
to
comments,
we
are
including
a
minimum
container
size
to
use
for
calculation
of
the
capacity
of
aboveground
storage
tanks
and
completely
buried
containers.
The
55­
gallon
container
is
the
most
widely
used
commercial
bulk
47
container,
and
these
containers
are
easily
counted.
Containers
below
55
gallons
in
capacity
are
typically
end­
use
consumer
containers.
Fifty­
five
gallon
containers
are
also
the
lowest
size
bulk
container
that
can
be
handled
by
a
human.
Containers
above
that
size
typically
require
equipment
for
movement
and
handling.
We
considered
a
minimum
container
size
of
one
barrel.
However,
a
barrel
or
42
gallons
is
a
common
volumetric
measurement
size
for
oil,
but
is
not
a
common
container
size.
Therefore,
it
would
not
be
appropriate
to
institute
a
42
gallon
minimum
container
size.

You
need
only
count
containers
of
55
gallons
or
greater
in
the
calculation
of
the
regulatory
threshold.
You
need
not
count
containers,
like
pints,
quarts,
and
small
pails,
which
have
a
storage
capacity
of
less
than
55
gallons.
Some
SPCC
facilities
might
therefore
drop
out
of
the
regulated
universe
of
facilities.
You
should
note,
however,
that
EPA
retains
authority
to
require
any
facility
subject
to
its
jurisdiction
under
section
311(
j)
of
the
CWA
to
prepare
and
implement
an
SPCC
Plan,
or
applicable
part,
to
carry
out
the
purposes
of
the
Act.

While
some
commenters
had
suggested
a
higher
threshold
level,
we
believe
that
inclusion
of
containers
of
55
gallons
or
greater
within
the
calculation
for
the
regulatory
threshold
is
necessary
to
ensure
environmental
protection.
If
we
finalized
a
higher
minimum
size,
the
result
in
some
cases
would
be
large
amounts
of
aggregate
capacity
that
would
not
be
counted
for
SPCC
purposes,
and
would
therefore
be
unregulated,
posing
a
threat
to
the
environment.
We
believe
that
it
is
not
necessary
to
apply
SPCC
or
FRP
rules
requiring
measures
like
secondary
containment,
inspections,
or
integrity
testing,
to
containers
smaller
than
55
gallons
storing
oil
because
a
discharge
from
these
containers
generally
poses
a
smaller
risk
to
the
environment.
Furthermore,
compliance
with
the
rules
for
these
containers
could
be
extremely
burdensome
for
an
owner
or
operator
and
could
upset
manufacturing
operations,
while
providing
little
or
no
significant
increase
in
protection
of
human
health
or
the
environment.
Many
of
these
smaller
containers
are
constantly
being
emptied,
replaced,
and
relocated
so
that
serious
corrosion
will
likely
soon
be
detected
and
undetected
leaks
become
highly
unlikely.
While
we
realize
that
small
discharges
may
harm
the
environment,
depending
on
where
and
when
the
discharge
occurs,
we
believe
that
this
measure
will
allow
facilities
to
concentrate
on
the
prevention
and
containment
of
discharges
of
oil
from
those
sources
most
likely
to
present
a
more
significant
risk
to
human
health
and
the
environment.

Animal
fats,
vegetable
oils.
A
facility
storing
or
using
animal
fats
or
vegetable
oils
(whether
edible
or
not)
is
subject
to
part
112
if
there
is
a
reasonable
possibility
of
discharge
as
described
in
§112.
1(
b)
from
such
facility,
and
the
facility
meets
regulatory
threshold
criteria.
The
scope
of
the
rule
encompasses
all
types
of
oils,
not
merely
petroleum
oil.

In
1995,
Congress
enacted
the
Edible
Oil
Regulatory
Reform
Act
(EORRA),
33
U.
S.
C.
2720.
That
statute
mandates
that
most
Federal
agencies
differentiate
between
and
establish
separate
classes
for
various
types
of
oils,
specifically:
animal
fats
and
oils
and
greases,
and
fish
and
marine
mammal
oils;
oils
of
vegetable
origin;
petroleum
oils,
48
and
other
non­
petroleum
oils
and
greases.
In
differentiating
between
these
classes
of
oils,
Federal
agencies
are
directed
to
consider
differences
in
the
physical,
chemical,
biological,
and
other
properties,
and
in
the
environmental
effects,
of
the
classes.
In
response
to
EORRA,
as
noted
above,
we
have
divided
the
requirements
of
the
rule
by
subparts
for
facilities
storing
or
using
the
various
classes
of
oils
listed
in
that
act.

Because
at
the
present
time
EPA
has
not
proposed
differentiated
SPCC
requirements
for
public
notice
and
comment,
the
requirements
for
facilities
storing
or
using
all
classes
of
oil
will
remain
the
same.
However,
we
have
published
an
advance
notice
of
proposed
rulemaking
seeking
comments
on
how
we
might
differentiate
among
the
requirements
for
the
facilities
storing
or
using
various
classes
of
oil.
64
FR
17227,
April
8,
1999.
If
after
considering
these
comments,
there
is
adequate
justification
for
differentiation
among
the
requirements
for
those
facilities,
we
will
propose
rule
changes.

Appalachian
producers,
small
facilities,
stripper
oil
and
gas
facilities,
oil­
water
separators.
The
"storage
capacity"
definition
is
applicable
to
both
large
and
small
storage
and
use
capacity,
no
matter
where
located,
because
both
types
of
facilities
have
the
same
possibility
of
discharge
as
described
in
§112.
1(
b).
The
same
rationale
applies
to
stripper
oil
and
gas
well
facilities,
and
to
oil­
water
separators.
An
owner
or
operator
of
a
small
facility
above
the
regulatory
threshold
is
subject
to
the
rule,
and
needs
to
know
how
to
calculate
his
storage
or
use
capacity.

Farms.
We
also
disagree
that
we
should
exempt
farm
operations
because
such
operations
may
be
the
source
of
a
discharge
as
described
in
§112.1(
b).
We
have,
however,
raised
the
regulatory
threshold
to
a
storage
or
use
capacity
greater
than
1,
320
gallons,
which
will
have
the
effect
of
exempting
many
small
farm
facilities
from
the
scope
of
the
rule.

Floating
fuel
tanks.
We
also
note
that
barges
which
store
oil,
are
permanently
moored
or
fastened
to
the
shore,
and
are
no
longer
used
for
transportation,
are
no
longer
vessels,
but
bulk
storage
containers
that
are
part
of
an
offshore
facility.
Likewise,
a
container,
whether
onshore
or
offshore,
which
was
formerly
used
for
transportation,
such
as
a
truck
or
railroad
car,
which
now
is
used
to
store
oil,
is
no
longer
used
for
a
transportation
purpose,
and
is
a
bulk
storage
container.

Largest
unit.
We
disagree
that
the
risk
posed
by
a
facility
is
more
accurately
measured
by
the
size
of
the
largest
individual
unit
at
the
facility
rather
than
the
facility's
aggregate
storage
capacity.
More
than
one
unit
may
fail
at
once.
For
example,
permanently
manifolded
containers
are
designed,
installed,
and/
or
operated
in
such
a
manner
that
multiple
containers
function
as
one
storage
unit.
In
a
worst
case
discharge
scenario,
a
single
failure
could
cause
a
discharge
as
described
in
§112.1(
b)
of
the
contents
of
more
than
one
container.

No
threshold.
We
disagree
that
we
should
omit
the
capacity
criterion
for
total
storage
capacity
at
a
facility,
and
instead
focus
on
tank
size.
More
than
one
container
may
fail
49
at
the
same
time
due
to
human
error
or
a
catastrophic
event
whether
the
containers
are
interconnected
or
not.
For
example,
permanently
manifolded
containers
are
designed,
installed,
and/
or
operated
in
such
a
manner
that
multiple
containers
function
as
one
storage
unit.
In
a
worst
case
discharge
scenario,
a
single
failure
could
cause
a
discharge
as
described
in
§112.1(
b)
of
the
contents
of
more
than
one
container.

Oil­
filled
equipment.
Types
of
containers
counted
as
storage
capacity
would
include
flo­
through
separators,
tanks
used
for
"emergency"
storage,
test
tanks,
transformers,
and
other
oil­
filled
equipment.
This
equipment
may
also
experience
a
discharge
as
described
in
§112.1(
b)
and
is
therefore
properly
regulated
under
the
SPCC
program.

Treatment
tanks.
We
agree
with
the
commenter
that
certain
wastewater
treatment
facilities
or
parts
thereof
should
be
exempted
from
the
rule,
if
used
exclusively
for
wastewater
treatment
and
not
used
to
meet
any
other
requirement
of
part
112.
We
have
therefore
amended
the
rule
to
reflect
that
agreement
(see
§112.1(
d)(
6)).
No
longer
subject
to
the
rule
would
be
wastewater
treatment
facilities
or
parts
thereof
such
as
treatment
systems
at
POTWs
and
industrial
facilities
treating
oily
wastewater.

Many
of
these
wastewater
treatment
facilities
or
parts
thereof
are
subject
to
NPDES
or
state­
equivalent
permitting
requirements
that
involve
operating
and
maintaining
the
facility
to
prevent
discharges.
40
CFR
122.41(
e).
The
NPDES
or
state­
equivalent
process
ensures
review
and
approval
of
the
facility's:
plans
and
specifications;
operation/
maintenance
manuals
and
procedures;
and,
Stormwater
Pollution
Prevention
Plans,
which
may
include
Best
Management
Practice
Plans
(BMP).

Many
affected
facilities
are
subject
to
a
BMP
prepared
under
an
NPDES
permit.
Some
of
those
plans
provide
protections
equivalent
to
SPCC
Plans.
BMPs
are
additional
conditions
which
may
supplement
effluent
limitations
in
NPDES
permits.
Under
section
402(
a)(
1)
of
the
CWA,
BMPs
may
be
imposed
when
the
Administrator
determines
that
such
conditions
are
necessary
to
carry
out
the
provisions
of
the
Act.
See
40
CFR
122.44(
k).
CWA
section
304(
e)
authorizes
EPA
to
promulgate
BMPs
as
effluent
limitations
guidelines.
NPDES
rules
provide
for
BMPs
when:
authorized
under
section
304(
e)
of
the
CWA
for
the
control
of
toxic
pollutants
and
hazardous
substances;
numeric
limitations
are
infeasible;
or,
the
practices
are
reasonably
necessary
to
achieve
effluent
limitations
and
standards
to
carry
out
the
purposes
of
the
CWA.
In
addition,
each
NPDES
or
state
equivalent
permit
for
a
wastewater
treatment
system
must
contain
operation
and
maintenance
requirements
to
reduce
the
risk
of
discharges.
40
CFR
122.41(
e).

Additionally,
some
wastewater
is
pretreated
prior
to
discharge
to
a
permitted
wastewater
treatment
facility.
The
CWA
authorizes
EPA
to
establish
pretreatment
standards
for
pollutants
that
pass
through
or
interfere
with
the
operation
of
POTWs.
The
General
Pretreatment
Regulations
(GPR),
which
set
for
the
framework
for
the
implementation
of
categorical
pretreatment
standards,
are
found
at
40
CFR
part
403.
The
GPR
prohibit
a
user
from
introducing
a
pollutant
into
a
POTW
which
causes
pass
through
or
interference.
40
CFR
403.5(
a)(
1).
More
specifically,
the
GPR
also
prohibit
50
the
introduction
into
of
POTW
of
"petroleum,
oil,
nonbiodegradable
cutting
oil,
or
products
of
mineral
oil
origin
in
amounts
that
will
cause
interference
or
pass
through.
40
CFR
403.5(
b)(
6).
EPA
believes
that
the
GPR
and
the
more
specific
categorical
pretreatment
standards,
some
of
which
allow
indirect
dischargers
to
adopt
a
BMP
as
an
alternative
way
to
meet
pretreatment
standards,
will
work
to
prevent
the
discharge
of
oil
from
wastewater
treatment
systems
into
navigable
waters
or
adjoining
shorelines
by
way
of
a
POTW.

However,
if
a
wastewater
facility
or
part
thereof
is
used
for
the
purpose
of
storing
oil,
then
there
is
no
exemption,
and
its
capacity
must
be
counted
as
part
of
the
storage
capacity
of
the
facility.
Any
oil
storage
capacity
associated
with
or
incidental
to
these
wastewater
treatment
facilities
or
parts
thereof
continues
to
be
subject
to
part
112.
At
permitted
wastewater
treatment
facilities,
storage
capacity
includes
bulk
storage
containers,
hydraulic
equipment
associated
with
the
treatment
process,
containers
used
to
store
oil
which
feed
an
emergency
generator
associated
with
wastewater
treatment,
and
slop
tanks
or
other
containers
used
to
store
oil
resulting
from
treatment.
Some
flow
through
treatment
such
as
oil/
water
separators
have
a
storage
capacity
within
the
treatment
unit
itself.
This
storage
capacity
is
subject
to
the
rule.
An
example
of
a
wastewater
treatment
unit
that
functions
as
storage
is
a
treatment
unit
that
accumulates
oil
and
performs
no
further
treatment,
such
as
a
bulk
storage
container
used
to
separate
oil
and
water
mixtures,
in
which
oil
is
stored
in
the
container
after
removal
of
the
water
in
the
separation/
treatment
process.

We
do
not
consider
wastewater
treatment
facilities
or
parts
thereof
at
an
oil
production,
oil
recovery,
or
oil
recycling
facility
to
be
wastewater
treatment
for
purposes
of
this
paragraph.
These
facilities
generally
lack
NPDES
or
state­
equivalent
permits
and
thus
lack
the
protections
that
such
permits
provide.
Production
facilities
are
normally
unmanned
and
therefore
lack
constant
human
oversight
and
inspection.
Produced
water
generated
by
the
production
process
normally
contains
saline
water
as
a
contaminant
in
the
oil,
which
might
aggravate
environmental
conditions
in
addition
to
the
toxicity
of
the
oil
in
the
case
of
a
discharge.

Additionally,
the
goal
of
an
oil
production,
oil
recovery,
or
oil
recycling
facility
is
to
maximize
the
production
or
recovery
of
oil,
while
eliminating
impurities
in
the
oil,
including
water,
whereas
the
goal
of
a
wastewater
treatment
facility
is
to
purify
water.
Neither
an
oil
production
facility,
nor
an
oil
recovery
or
oil
recycling
facility
treats
water,
instead
they
treat
oil.
For
purposes
of
this
exemption,
produced
water
is
not
considered
wastewater
and
treatment
of
produced
water
is
not
considered
wastewater
treatment.
Therefore,
a
facility
which
stores,
treats,
or
otherwise
uses
produced
water
remains
subject
to
the
rule.
At
oil
drilling,
oil
production,
oil
recycling,
or
oil
recovery
facilities,
treatment
units
subject
to
the
rule
include
open
oil
pits
or
ponds
associated
with
oil
production
operations,
oil/
water
separators
(gun
barrels),
and
heater/
treater
units.
Open
oil
pits
or
ponds
function
as
another
form
of
bulk
storage
container
and
are
not
used
for
wastewater
treatment.
Open
oil
pits
or
ponds
also
pose
numerous
environmental
risks
to
birds
and
other
wildlife.
51
Examples
of
wastewater
treatment
facilities
or
parts
thereof
used
to
meet
a
part
112
requirement
include
an
oil/
water
separator
used
to
meet
any
SPCC
requirement.
Oil/
water
separators
used
to
meet
SPCC
requirements
include
oil/
water
separators
used
as
general
facility
secondary
containment
(i.
e.,
§112.7(
c),
secondary
containment
requirements
for
loading
and
unloading
(i.
e.,
§112.7(
h)),
and
for
facility
drainage
(i.
e.,
§112.8(
b)
or
§112.9(
b)).

Whether
a
wastewater
treatment
facility
or
part
thereof
is
used
exclusively
for
wastewater
treatment
(i.
e.,
not
storage
or
other
use
of
oil)
or
used
to
satisfy
a
requirement
of
part
112
will
often
be
a
facility
specific
determination
based
on
the
activity
associated
with
the
facility
or
part
thereof.
Only
the
portion
of
the
facility
(except
at
an
oil
production,
oil
recovery,
or
oil
recycling
facility)
used
exclusively
for
wastewater
treatment
and
not
used
to
meet
any
part
112
requirement
is
exempt
from
part
112.
Storage
or
use
of
oil
at
such
a
facility
will
continue
to
be
subject
to
part
112.

Although
we
exempt
wastewater
treatment
facilities
or
parts
thereof
from
the
rule
under
certain
circumstances,
a
mixture
of
wastewater
and
oil
still
is
"oil"
under
the
statutory
and
regulatory
definition
of
the
term
(33
USC
1321(
a)(
1)
and
40
CFR
110.2
and
112.2).
Thus,
while
we
are
excluding
from
the
scope
of
the
rule
certain
wastewater
treatment
facilities
or
parts
thereof,
a
discharge
of
wastewater
containing
oil
to
navigable
waters
or
adjoining
shorelines
in
a
"harmful
quantity"
(40
CFR
Part
110)
is
prohibited.
Thus,
to
avoid
such
discharges,
we
would
expect
owners
or
operators
to
comply
with
the
applicable
permitting
requirements,
including
best
management
practices
and
operation
and
maintenance
provisions.

USTs.
We
agree
that
completely
buried
tanks
that
are
subject
to
all
of
the
technical
requirements
of
40
CFR
part
280
or
a
State
program
approved
under
40
CFR
part
281
should
be
exempted
from
part
112,
and
have
taken
that
action.
See
section
V.
C
of
this
document.

Vaulted
tanks.
We
also
disagree
that
we
should
exempt
aboveground,
vaulted
tanks
from
part
112.
Vaulted
tanks
are
generally
excluded
from
the
scope
of
40
CFR
part
280.
The
definition
of
"underground
storage
tank"
at
40
CFR
280.12(
i)
excludes
from
its
scope
a
"storage
tank
situated
in
an
underground
area
(such
as
a
basement,
cellar,
mineworking,
drift,
shaft,
or
tunnel)
if
the
storage
tank
is
situated
upon
or
above
the
surface
of
the
floor."
These
tanks
might
reasonably
experience
a
discharge
as
described
in
§112.1(
b).
Therefore,
it
is
reasonable
that
they
be
within
the
scope
of
part
112.
Merely
because
these
tanks
are
the
subject
of
local
fire
and
safety
regulations
does
not
guarantee
that
there
will
be
adequate
environmental
protection
to
prevent
a
discharge
as
described
in
§112.1(
b),
because
that
is
not
the
purpose
of
those
regulations.
Such
codes
may
provide
lesser
protection
than
part
112.
For
example,
NFPA
30:
2­
3.4.3(
b)
specifically
indicates
that
a
dike
need
only
provide
containment
for
the
largest
tank,
while
part
112
requires
freeboard
for
precipitation.

Volume,
not
capacity.
We
also
disagree
that
we
should
base
the
regulation
on
the
amount
of
oil
actually
stored
in
the
tanks.
In
most
instances
the
shell
capacity
of
a
52
container
will
define
its
storage
capacity.
The
shell
capacity
(or
nominal
or
gross
capacity)
is
the
amount
of
oil
that
a
container
is
designed
to
hold.
If
a
certain
portion
of
a
container
is
incapable
of
storing
oil
because
of
its
integral
design,
for
example
electrical
equipment
or
other
interior
component
might
take
up
space,
then
the
shell
capacity
of
the
container
is
reduced
to
the
volume
the
container
might
hold.
When
the
integral
design
of
a
container
has
been
altered
by
actions
such
as
drilling
a
hole
in
the
side
of
the
container
so
that
it
cannot
hold
oil
above
that
point,
shell
capacity
remains
the
measure
of
storage
capacity
because
such
alteration
can
be
altered
again
at
will
to
restore
the
former
storage
capacity.
When
the
alteration
is
an
action
such
as
the
installation
of
a
double
bottom
or
new
floor
to
the
container,
the
integral
design
of
the
container
has
changed,
and
may
result
in
a
reduction
in
shell
capacity.
We
disagree
that
operating
volume
should
be
the
measurement,
because
the
operating
volume
of
a
tank
can
be
changed
at
will
to
below
its
shell
capacity.

The
key
to
the
definition
of
"storage
capacity"
is
the
availability
of
the
container
for
drilling,
producing,
gathering,
storing,
processing,
refining,
transferring,
distributing,
using,
or
consuming
oil;
whether
it
is
available
for
one
of
those
uses
or
whether
it
is
permanently
closed.
Containers
available
for
one
of
the
above
described
uses
count
towards
storage
capacity,
those
not
used
for
these
activities
do
not.

IV­
E(
1)­
2
Other
comments
Comments:
Scope
of
rule.
"EPA
has
misinterpreted
its
authority
under
section
311(
j)(
1)
and
has
exceeded
its
jurisdiction
in
both
existing
and
proposed
regulations.
Section
311(
j)(
1)(
C)
provides
authority
to
require
spill
prevention
and
containment
equipment
rather
than
authority
to
regulate
facilities."
(32,
42)
We
should
clarify
whether
proposed
§112.1(
b)(
2)
and
§112.1(
b)(
3)
expanded
the
"scope
of
covered
facilities"
beyond
those
described
in
§112.
1(
b)(
1).
We
should
insert
"described
in
subparagraph
(1)"
after
"facilities"
in
subparagraphs
(2)
and
(3).
(L24)

Automotive
businesses.
We
should
exclude
from
part
112,
automotive
businesses
with
a
total
aboveground
storage
volume
of
new
or
used
oil
in
quantities
of
10,000
gallons
or
less,
and
aboveground
tanks
with
a
volume
of
2,
500
gallons
or
less.
However,
we
should
still
require
owners
or
operators
to
provide
adequate
secondary
containment
for
the
tanks,
report
releases
to
the
EPA
Administrator,
and
cleanup
releases
within
72
hours.
(71)

Mobile
containers.
Inclusion.
We
should
include
mobile
and
portable
container
capacity
within
this
calculation.
(L11)

Exclusion.
We
should
exclude
the
capacity
of
mobile
or
portable
containers
of
oil
from
a
facility's
total
aboveground
storage
capacity
determination.
(33,
89)

Production
facilities,
large
or
small.
We
should
modify
the
proposed
requirements
to
recognize
that
a
small
production
facility
presents
little
actual
threat
of
a
spill
(based
on
53
history
and
amount
of
oil
present).
(28)
We
could
inadvertently
cover
some
facilities
not
currently
covered
by
the
SPCC
rule.
The
commenter
explained
that
some
production
locations
may
have
total
storage
capacity
which
exceeds
the
volume
of
fluid
ever
stored
in
the
tanks.
(86)
We
should
exclude
production
tanks
because
aboveground
tanks
associated
with
producing
oil
and
gas
wells
are
small,
remotely
located
and
generally
constructed
to
API
Production
Standards.
(167)
Interprets
a
statement
in
the
preamble
to
mean
that
small
and
large
facility
classifications
would
not
apply
to
oil
production
facilities.
Asks
whether
this
assumption
is
true.
(L15)

Reasonable
expectation
of
discharge.
Many
SPCC­
regulated
facilities
are
not
located
near
a
permanent
surface
water
body,
so
an
accidental
discharge
from
them
will
rarely
reach
surface
waters.
(75,
79)
We
should
obtain
data
and
provide
specific
parameters
to
determine
whether
an
accidental
discharge
could
"reasonably
be
expected"
to
reach
navigable
waters.
(75)

Can
industry.
We
should
reconsider
the
scope
of
the
program
for
the
can­
making
industry,
already
governed
by
many
spill­
prevention
and
accidental
release
regulations.
(62)

Response:
Scope
of
rule.
Proposed
§112.1(
b)(
2)
and
(3)
(§
112.1(
b)(
3)
and
(4)
in
the
final
rule)
do
not
expand
the
applicability
of
the
rule
beyond
facilities
described
in
proposed
§112.1(
b)(
1).
In
response
to
the
commenter's
suggestion,
we
have
revised
§112.1(
b)
to
list
the
types
of
containers
that
may
be
subject
to
the
rule.
We
note,
in
response
to
comment,
that
we
do
not
regulate
all
facilities
in
the
United
States.
We
only
regulate
facilities
storing
or
using
oil
over
the
regulatory
threshold
amount
from
which
there
is
a
reasonable
possibility
of
a
discharge
as
described
in
§112.
1(
b).
CWA
section
311(
j)(
1)(
C)
authorizes
EPA
to
establish
procedures,
methods,
and
equipment,
and
other
requirements
for
equipment
to
prevent
and
contain
discharges
of
oil
from
onshore
facilities.
This
rule
establishes
such
procedures,
methods,
and
in
some
cases
equipment
or
other
requirements
for
equipment
to
prevent
and
contain
discharges
from
facilities
and,
thus,
is
consistent
with
that
authority.

Automotive
businesses.
We
disagree
that
we
should
exclude
from
part
112,
automotive
businesses
with
a
total
aboveground
storage
volume
of
new
or
used
oil
in
quantities
of
10,000
gallons
or
less,
and
aboveground
tanks
with
a
volume
of
2,
500
gallons
or
less
whether
we
required
the
owner
or
operator
to
provide
adequate
secondary
containment
for
the
tanks,
report
releases
to
the
EPA
Administrator,
and
cleanup
releases
within
72
hours
or
not.
Such
facilities
could
be
the
source
of
a
discharge
as
described
in
§112.1(
b)
and
must
therefore
be
regulated.

Mobile
containers.
We
disagree
that
we
should
exclude
the
capacity
of
mobile
or
portable
containers
of
oil
from
a
facility's
total
aboveground
storage
capacity
determination.
A
mobile
facility
could
be
the
source
of
a
discharge
as
described
in
§112.1(
b)
and
must
therefore
be
regulated.
54
Production
facilities,
large
or
small.
We
do
not
differentiate
in
the
rule
between
large
and
small
facilities
because
the
possibility
of
a
discharge
as
described
in
§112.
1(
b)
is
the
same
for
both.
Therefore,
any
facility
with
the
requisite
storage
or
use
capacity,
whether
a
small
or
large
production
facility,
is
subject
to
part
112.
We
note
that
shell
capacity
is
the
measure
of
capacity.
See
the
discussion
concerning
shell
capacity
in
section
IV­
E(
1)­
1
of
this
document.

Reasonable
expectation
of
discharge.
We
disagree
that
we
could
or
should
set
specific
parameters
to
determine
whether
an
accidental
discharge
could
reasonably
be
expected
to
reach
protected
areas.
Such
a
determination
is
dependent
upon
facilityspecific
and
location­
specific
factors.

Can
industry.
The
can­
making
industry
may
store
or
use
oil.
If
a
can
industry
facility
may
reasonably
be
expected
to
discharge
oil
as
described
in
§112.1(
b)
and
has
the
requisite
storage
or
use
capacity,
it
is
subject
to
the
rule.
However,
an
owner
or
operator
of
an
SPCC
facility
may
use
an
alternative
plan
as
a
substitute
for
an
SPCC
Plan
if
such
plan
meets
all
applicable
part
112
requirements
and
is
cross­
referenced
to
such
requirements.
An
owner
or
operator
also
may
supplement
an
alternative
plan
that
does
not
meet
all
part
112
provisions
with
sections
that
do
meet
part
112.

IV
­
E(
2):
Applicability
­
Electrical
and
other
oil­
filled
equipment
Background:
In
the
1991
preamble,
we
noted
that
certain
facilities
may
have
equipment,
such
as
electrical
transformers,
that
contains
significant
quantities
of
oil
necessary
for
operational
purposes.
We
also
clarified
that
an
owner
or
operator
must
consider
the
oil
storage
capacity
of
oil­
filled
equipment
when
determining
total
storage
capacity
for
subjection
to
SPCC
regulation.
Equipment
use
for
operational
purposes
is
not
subject
to
the
bulk
storage
container
provisions,
such
as
§§
112.8(
c)
and
112.9(
d).
However,
such
equipment
is
subject
to
other
applicable
SPCC
requirements,
including
the
general
requirements
in
§112.7.

Comments:
Authority.

No
CWA
authority.
"To
be
consistent
with
legislative
intent,
the
Agency
should
make
clear
that
the
SPCC
requirements
do
not
apply
to
electrical
equipment
and
to
other
devices
that
use
oil
operationally."
(3,
66,
92,
98,
100,
104,
125,
132,
134,
138,
156,
162,
163,
164,
170,
175,
184,
189,
L2,
L6,
L7,
L14,
L16,
L20)

Rule
activities
­
storage
or
use
of
oil.
We
should
clarify
whether
oil­
filled
equipment,
such
as
transformers
and
oil
breakers,
are
oil
storage
tanks.
(66)
Because
"electrical
equipment
does
not
`consume'
oil
or
oil
products,"
and
because
none
of
the
other
activities
listed
are
relevant
to
electrical
equipment
in
the
applicability
section,
the
rule
does
not
apply
to
it.
Activities
listed
in
the
§112.
1(
b)(
1)
applicability
criteria
involve
oil
movement
from
one
storage
vessel
to
another,
whereas
dielectric
fluid
remains
stationary
and
does
not
pose
a
risk
to
the
environment.
(125,
189)
We
should
add
a
§112.1(
d)(
5)
to
specifically
55
exclude
from
the
SPCC
rule,
equipment
or
machinery
containing
oil
for
operational
use
rather
than
storage.
(138)
Asks
us
to
confirm
that
facilities
with
oil­
filled
electrical
equipment
are
not
engaged
in
the
§112.1(
b)
activities
and
are
not
subject
to
SPCC
requirements.
(184)
We
should
exclude
oil­
filled
equipment
from
the
SPCC
regulations.
We
should
expand
the
examples
of
equipment
(that
contain
significant
quantities
of
oil
for
operational
purposes
rather
than
storage
purposes)
identified
in
the
preamble
to
include
transformers,
capacitors,
and
other
manufacturing
equipment
such
as
small
lube
oil
systems,
fat
traps,
and
oil­
water
separators.
(L6)

Facility
definition.
Substations
and
other
installations
containing
electrical
equipment
are
not
facilities
as
defined
in
proposed
§112.2(
f).
Electrical
equipment
does
not
fall
under
§112.1(
b)(
1)
since
this
section
applies
to
facilities
that
consume
oil,
and
the
proposed
§112.2(
f)
definition
does
not
include
units
that
consume
oil.
(125,
189)
We
should
base
our
§112.1(
b)
applicability
criteria
on
the
proposed
§112.2(
f)
facility
definition
so
that
the
rule
applies
to
oil
well
drilling
operations,
oil
production,
oil
refining,
oil
storage,
and
waste
treatment
only.
(189)

UST
rules.
The
Underground
Storage
Tank
(UST)
program
(part
280)
excludes
equipment
or
machinery
containing
regulated
substances
(i.
e.,
oil
or
dielectric
fluid)
for
operational
purposes,
such
as
hydraulic
lift
tanks
and
electrical
equipment
tanks.
(170,
189)

Bulk
storage.
We
should
not
consider
electrical
equipment
as
bulk
storage
containers
and
that
proposed
§§
112.8(
c)
and
112.9(
d)
should
not
apply
to
such
equipment.
(41,
170,
164,
184)
We
should
specifically
state
in
the
rule
–
not
the
preamble
–
that
electrical
equipment
is
not
a
bulk
tank
under
the
SPCC
rule.
(175)
Products
used
in
electrical
equipment
are
distinct
from
oils
stored
in
bulk
storage
tanks.
(184)

Whose
storage
capacity?
Frequently,
the
power
company
–
not
the
facility
owner
or
operator
–
owns
the
transformer.
In
such
a
case,
must
the
owner
or
operator
must
include
the
equipment's
oil
capacity
in
determining
applicability?
(39)

Risk.
"First,
electrical
equipment
poses
substantially
less
risk
to
the
environment
than
do
tanks,
and
second,
many
tank
requirements
are
simply
inappropriate
for
electrical
equipment."
(39,
41,
66,
125,
164,
170)
Electrical
equipment
poses
no
sufficient
environmental
risk
because
of
stringent
design,
construction,
and
inspection
standards.
(184,
189)

Cable
systems.
"The
Agency
should
exclude
underground
electric
cable
systems
from
SPCC
requirements,
regardless
of
the
Agency's
position
on
other
types
of
electrical
equipment....
...
The
technology
simply
does
not
exist
currently
to
apply
the
secondary
containment,
inspection,
and
integrity
testing
requirements
of
the
SPCC
program
to
underground
cable
systems."
(125)
We
56
should
exclude
electric
cable
systems
from
the
rule,
since
such
systems
include
tanks
and
reservoirs
for
back­
up
oil
and
are
surrounded
by
dielectric
fluids.
We
should
recognize
that
electric
utility
facilities
include
features
that
serve
operational
functions
and
reduce
risks
associated
with
potential
discharges.
If
we
do
not
exclude
electric
cable
systems
from
SPCC
requirements,
then
we
should
require
owners
or
operators
to
prepare
contingency
plans,
but
should
delete
the
proposed
requirement
to
submit
contingency
plans
when
containment
or
diversion
is
not
feasible.
(175)
We
should
exclude
electrical
equipment
from
the
SPCC
program
or
tailor
the
program
to
reflect
specific
electrical
equipment
characteristics.
Due
to
the
location,
size,
and
nature
of
underground
cable
systems
that
extend
many
miles
under
urban
streets,
it
is
impossible
for
such
systems
to
comply
with
SPCC
tank
requirements.
SPCC
requirements
cannot
be
applied
to
dielectric
fluid­
filled
cable
systems
because
the
design,
construction,
and
operation
of
such
systems
differ
from
tank
systems.
(125,
189)

Response:
Authority,
use
of
oil.
We
disagree
that
operational
equipment
is
not
subject
to
the
SPCC
rule.
We
have
amended
§112.1(
b)
to
clarify
that
using
oil,
for
example
operationally,
may
subject
a
facility
to
SPCC
jurisdiction
as
long
as
the
other
applicability
criteria
apply,
for
example,
oil
storage
capacity,
or
location.
Such
a
facility
might
reasonably
be
expected
to
discharge
oil
as
described
in
§112.1(
b).
Therefore,
the
prevention
of
discharges
from
such
facility
falls
within
the
scope
of
the
statute.
However,
we
have
distinguished
the
bulk
storage
of
oil
from
the
operational
use
of
oil.
We
define
"bulk
storage
container"
in
the
final
rule
to
mean
any
container
used
to
store
oil.
The
storage
of
oil
may
be
prior
to
use,
while
being
used,
or
prior
to
further
distribution
in
commerce.
For
clarity,
we
have
specifically
excluded
oil­
filled
electrical,

operating,
or
manufacturing
equipment
from
the
"bulk
storage
container"
definition.

Facilities
that
use
oil
operationally
include
electrical
substations,
facilities
containing
electrical
transformers,
and
certain
hydraulic
or
manufacturing
equipment.
The
requirements
for
bulk
storage
containers
may
not
always
apply
to
these
facilities
since
the
primary
purpose
of
this
equipment
is
not
the
storage
of
oil
in
bulk.
Facilities
with
equipment
containing
oil
for
ancillary
purposes
are
not
required
to
provide
the
secondary
containment
required
for
bulk
storage
facilities
(§
112.
8(
c))
and
onshore
production
facilities
(§
112.
9(
c)),
nor
implement
the
other
provisions
of
§112.
8(
c)
or
§112.
9(
c).
Oil­
filled
equipment
must
meet
other
SPCC
requirements,
for
example,
the
general
requirements
of
this
part,
including
§112.7(
c),
to
provide
appropriate
containment
and/
or
diversionary
structures
to
prevent
discharged
oil
from
reaching
a
navigable
watercourse.
The
general
requirement
for
secondary
containment,
which
can
be
provided
by
various
means
including
drainage
systems,
spill
diversion
ponds,
etc.,
will
provide
for
safety
and
also
the
needs
of
section
311(
j)(
1)(
C)
of
the
CWA.
EPA
will
continue
to
evaluate
whether
the
general
secondary
containment
requirements
found
in
§112.7(
c)
should
be
modified
for
small
electrical
and
other
types
of
equipment
which
use
oil
for
operating
purposes.
We
intend
to
publish
a
notice
asking
for
additional
data
and
comment
on
this
issue.
57
In
addition,
a
facility
may
deviate
from
any
inappropriate
SPCC
requirements
if
the
owner
or
operator
explains
his
reasons
for
nonconformance
and
provides
equivalent
environmental
protection
by
some
other
means.
See
§112.7(
a)(
2).
See
also
§112.7(
d).

Facility
definition.
We
disagree
that
our
authority
does
not
extend
to
facilities.
Section
311(
j)(
1)(
C)
of
the
statute
authorizes
and
requires
the
President
(and
EPA,
through
delegation
in
Executive
Order
12777,
56
FR
54757,
October
22,
1991)
to
issue
regulations
consistent
with
the
National
Oil
and
Hazardous
Substances
Pollution
Contingency
Plan,
and
consistent
with
maritime
safety
and
with
marine
and
navigation
laws,
which
establish
"procedures,
methods,
and
equipment
and
other
requirements
for
equipment
to
prevent
discharges
of
oil
and
hazardous
substances
from
vessels
and
from
onshore
and
offshore
facilities,
and
to
contain
such
discharges."
This
language
authorizes
the
President
to
issue
oil
spill
prevention
rules
which
pertain
to
onshore
facilities
and
offshore
facilities
and
not
just
"equipment."

In
order
to
fulfill
the
statutory
mandate,
it
is
necessary
to
regulate
the
facilities
from
which
discharges
emanate.
Moreover,
although
the
term
"facility"
is
not
defined
in
the
statute,
both
"onshore
facility"
and
"offshore
facility"
are
defined
terms
in
CWA
section
311.
They
have
also
been
defined
terms
in
the
SPCC
rule
since
its
inception
in
1974.
In
the
1991
proposal,
EPA
proposed
a
definition
of
"facility"
to
implement
the
CWA.
That
definition
was
based
on
a
Memorandum
of
Understanding
(MOU)
between
the
Secretary
of
Transportation
and
the
EPA
Administrator
dated
November
24,
1971
(36
FR
24080).
The
MOU,
which
has
been
published
as
Appendix
A
to
part
112
since
December
11,
1973
(38
FR
34164,
34170),
defines
in
detail
what
constitutes
a
facility.
Thus,
there
has
long
been
a
common
understanding
of
the
term.
That
understanding
has
been
reinforced
by
frequent
use
of
the
term
in
context
within
the
SPCC
rule
since
it
became
effective
in
1974.
To
promote
clarity
and
to
maintain
all
definitions
in
one
place,
the
proposed
definition
has
been
finalized
in
this
rulemaking.

While
section
311(
j)(
1)(
C)
of
the
Act
may
not
explicitly
mention
jurisdictional
criteria,
section
311(
b)
of
the
Act
does.
Section
311(
b)
establishes
as
the
policy
of
the
United
States
that
there
shall
be
"no
discharges
of
oil
or
hazardous
substances
into
or
upon
the
navigable
waters
of
the
United
States,
adjoining
shorelines,
or
into
or
upon
the
waters
of
the
contiguous
zone,
or
in
connection
with
activities
under
the
Outer
Continental
Shelf
Lands
Act
or
the
Deepwater
Port
Act
of
1974,
or
which
may
affect
natural
resources
belonging
to,
appertaining
to,
or
under
the
exclusive
management
authority
of
the
United
States
(including
resources
under
the
Magnuson
Fishery
Conservation
and
Management
Act)."
Thus,
the
location
or
"jurisdictional"
criteria
contained
in
§112.1(
b)
are
appropriate
for
inclusion
in
the
rule.

UST
rules.
The
two
programs
(SPCC
and
UST)
have
different
purposes.
Therefore,
the
rules
differ
in
important
aspects.
Operational
equipment
is
58
included
under
the
SPCC
rules
because
such
equipment
may
experience
a
discharge
as
described
in
§112.1(
b).

Bulk
storage.
We
agree
and
clarify
in
today's
rule
that
oil­
filled
electrical,
operating,
or
manufacturing
equipment
is
not
a
bulk
storage
container.
See
the
discussion
on
the
applicability
of
the
rule
to
electrical
and
other
operating
equipment
under
§112.1(
b)
in
today's
preamble
and
this
section.
See
also
the
definition
of
"bulk
storage
container"
in
§112.2.
For
a
discussion
of
minimum
size
containers
to
which
the
rule
applies,
see
the
discussion
under
§112.1(
d)(
2)(
ii)
in
today's
preamble
and
in
section
V.
G
of
this
document.

Regulatory
threshold,
storage
capacity.
Oil
stored
in
operating
equipment
counts
as
storage
capacity
for
purposes
of
determining
whether
the
facility
meets
the
regulatory
threshold
of
greater
than
1,320
gallons
for
aboveground
containers.
Such
equipment
or
machinery
might
reasonably
be
expected
to
discharge
oil
as
described
in
§112.1(
b).
Aggregate
capacity
is
important
even
if
the
equipment
is
not
hydraulically
interconnected
because
if
a
catastrophic
event
were
to
occur,
all
of
the
equipment
might
fail
at
once
and
discharge
oil.
The
key
to
the
definition
of
storage
capacity
is
the
availability
of
the
container
for
drilling,
producing,
gathering,
storing,
processing,
refining,
transferring,
distributing,
using,
or
consuming
oil;
whether
it
is
available
for
one
of
those
uses
or
whether
it
is
permanently
closed.
Containers
available
for
one
of
the
above
described
uses
count
towards
storage
capacity,
those
not
used
for
these
activities
do
not.
Types
of
containers
counted
as
storage
capacity
would
include
flothrough
separators,
tanks
used
for
"emergency"
storage,
transformers,
and
other
oilfilled
equipment.

In
response
to
the
comment
that
the
power
company
–
not
the
facility
owner
or
operator
–
frequently
owns
the
transformers
located
at
the
facility,
we
note
that
the
SPCC
regulations
generally
prescribe
requirements
for
the
owner
or
operator
of
a
facility.
Either
or
both
may
be
responsible
for
part
112
compliance.

Risk.
We
also
disagree
that
electrical
equipment
poses
no
environmental
risk
because
of
stringent
design,
construction,
and
inspection
standards.
Such
standards
are
not
necessarily
aimed
at
preventing
discharges
as
described
in
§112.
1(
b),
and
a
facility
containing
such
equipment
might
reasonably
be
expected
to
experience
a
discharge.
Therefore,
it
may
fall
within
the
scope
of
the
statute.

Specific
rules.
We
agree
that
differentiated
rules
may
be
warranted
for
facilities
using
electrical
or
other
oil­
filled
operating
equipment.
In
1995,
Congress
enacted
the
Edible
Oil
Regulatory
Reform
Act
(EORRA),
33
U.
S.
C.
2720.
That
statute
mandates
that
most
Federal
agencies
differentiate
between
and
establish
separate
classes
for
various
types
of
oils,
specifically:
animal
fats
and
oils
and
greases,
and
fish
and
marine
mammal
oils;
oils
of
vegetable
origin;
petroleum
oils,
and
other
non­
petroleum
oils
and
greases.
In
differentiating
between
these
classes
of
oils,
Federal
agencies
are
directed
to
consider
differences
in
the
physical,
chemical,
biological,
and
other
properties,
and
in
the
environmental
effects,
of
the
classes.
In
response
to
EORRA,
as
noted
above,
59
we
have
divided
the
requirements
of
the
rule
by
subparts
for
facilities
storing
or
using
the
various
classes
of
oils
listed
in
that
act.

Because
at
the
present
time
EPA
has
not
proposed
differentiated
SPCC
requirements
for
public
notice
and
comment,
the
requirements
for
facilities
storing
or
using
all
classes
of
oil
will
remain
the
same.
However,
we
have
published
an
advance
notice
of
proposed
rulemaking
seeking
comments
on
how
we
might
differentiate
among
the
requirements
for
the
facilities
storing
or
using
various
classes
of
oil.
64
FR
17227,
April
8,
1999.
If
after
considering
these
comments,
there
is
adequate
justification
for
differentiation
among
the
requirements
for
those
facilities,
including
facilities
with
electrical
or
other
oil­
filled
operating
equipment,
we
will
propose
rule
changes.

Deviations
are
available
when
a
requirement
is
not
appropriate
for
a
particular
kind
of
facility.
See
categories
X­
B
and
E
of
this
document,
and
§112.7(
a)(
2)
and
(d).

IV­
E(
3):
Minimum
container
size
­
§112.1(
d)(
2)
and
(5)

Background:
Under
§112.1(
d)(
2)
of
the
current
rule,
all
size
containers
are
counted
in
determining
the
storage
capacity
of
the
facility.
In
1991,
we
proposed
no
changes
in
the
size
of
a
container
which
must
be
counted.

Comments:
Exclude
small
containers.
"As
written,
this
captures
pints,
quarts,
equipment
reservoirs
of
any
size,
once
a
facility
determined
that
it
was
covered
under
this
regulation."
"Clearly,
compliance
with
these
requirements
for
all
containers
of
any
size
will
be
extremely
burdensome
for
some
of
the
regulated
community
and
will
greatly
upset
ongoing
manufacturing
operations,
while
providing
no
significant
increase
in
protection
of
human
health
and
the
environment."
(33,
62,
66,
115,
119,
127,
175,
190,
L7)

Suggested
thresholds
for
minimum
size­
aboveground
storage.

250
gallons
or
less.
(62).

55
gallons
or
less.
(29,
57,
103,
119,
L24)

660
gallons
or
less.
(22,
48,
67,
91,
92,
98,
106,
125,
133,
150,
167,
182,
187,
L14)

10,000
gallons.
(170)

25,000
gallons.
(189)

Response:
Minimum
container
size.
In
response
to
comments,
we
are
introducing
a
minimum
container
size
to
use
for
calculation
of
the
capacity
of
aboveground
storage
tanks
and
completely
buried
containers.
Therefore,
you
need
only
count
containers
of
55
gallons
or
greater
in
the
calculation
of
the
regulatory
threshold
for
storage
capacity.
60
You
need
not
count
containers,
like
pints,
quarts,
and
small
pails,
which
have
a
storage
capacity
of
less
than
55
gallons,
in
capacity
calculations.
Some
SPCC
facilities
might
therefore
drop
out
of
the
regulated
universe
of
facilities.
You
should
note,
however,
that
EPA
retains
authority
to
require
any
facility
subject
to
its
jurisdiction
under
section
311(
j)
of
the
CWA
to
prepare
and
implement
an
SPCC
Plan,
or
applicable
part,
to
carry
out
the
purposes
of
the
Act.

While
some
commenters
had
suggested
a
higher
threshold
level,
we
believe
that
inclusion
of
containers
of
55
gallons
or
greater
within
the
calculation
for
the
regulatory
threshold
is
necessary
to
ensure
environmental
protection.
If
we
finalized
a
higher
minimum
size,
the
result
in
some
cases
would
be
large
amounts
of
aggregate
capacity
that
would
not
be
counted
for
SPCC
purposes,
and
would
therefore
be
unregulated,
posing
a
threat
to
the
environment.
We
believe
that
it
is
not
necessary
to
apply
SPCC
or
FRP
rules
requiring
measures
like
secondary
containment,
inspections,
or
integrity
testing,
to
containers
smaller
than
55
gallons
storing
oil
because
a
discharge
from
these
containers
generally
poses
a
smaller
risk
to
the
environment.
Furthermore,
compliance
with
the
rules
for
these
containers
could
be
extremely
burdensome
for
an
owner
or
operator
and
could
upset
manufacturing
operations,
while
providing
little
or
no
significant
increase
in
protection
of
human
health
or
the
environment.
Many
of
these
smaller
containers
are
constantly
being
emptied,
replaced,
and
relocated
so
that
serious
corrosion
will
likely
soon
be
detected
and
undetected
leaks
become
highly
unlikely.
While
we
realize
that
small
discharges
may
harm
the
environment,
depending
on
where
and
when
the
discharge
occurs,
we
believe
that
this
measure
will
allow
facilities
to
concentrate
on
the
prevention
and
containment
of
discharges
of
oil
from
those
sources
most
likely
to
present
a
more
significant
risk
to
human
health
and
the
environment.

IV
­
G
Wastewater
Treatment
­
§112.1(
d)(
6).

Background:
In
1991,
EPA
proposed
various
changes
to
§112.1(
d)
concerning
exemptions
to
part
112,
and
received
comments
on
its
proposals.
Among
those
comments
was
one
suggesting
an
exemption
for
certain
treatment
systems.

Comments:
One
commenter
suggested
that
the
"§
112.1
exceptions
should
be
expanded
to
include
facility
storage
and
treatment
tanks
associated
with
`non­
contact
cooling
water
systems'
and/
or
`storm
water
retention
and
treatment
systems.
Although
these
tanks
are
designed
to
remove
spilled
oil
from
manufacturing
operations
and
parking
lot
runoff,
the
concentration
of
oil
in
the
water
at
any
given
time
would
be
insignificant.
These
tanks
are
typically
very
large,
i.
e.,
in
excess
of
100,000
gallons,
and
are
typically
not
contained
by
diked
walls
or
impervious
surfaces.
GM
believes
the
cost
to
contain
these
structures
could
be
better
spent
on
other
SPCC
regulatory
requirements."

Response:
We
agree
with
the
commenter
that
certain
wastewater
treatment
facilities
or
parts
thereof
should
be
exempted
from
the
rule,
if
used
exclusively
for
wastewater
treatment
and
not
used
to
meet
any
other
requirement
of
part
112.
We
have
therefore
61
amended
the
rule
to
reflect
that
agreement.
No
longer
subject
to
the
rule
would
be
wastewater
treatment
facilities
or
parts
thereof
such
as
treatment
systems
at
POTWs
and
industrial
facilities
treating
oily
wastewater.

Many
of
these
wastewater
treatment
facilities
or
parts
thereof
are
subject
to
NPDES
or
state­
equivalent
permitting
requirements
that
involve
operating
and
maintaining
the
facility
to
prevent
discharges.
40
CFR
122.41(
e).
The
NPDES
or
state­
equivalent
process
ensures
review
and
approval
of
the
facility's:
plans
and
specifications;
operation/
maintenance
manuals
and
procedures;
and,
Stormwater
Pollution
Prevention
Plans,
which
may
include
Best
Management
Practice
Plans
(BMP).
Many
affected
facilities
are
subject
to
a
BMP
prepared
under
an
NPDES
permit.
Some
of
those
plans
provide
protections
equivalent
to
SPCC
Plans.
BMPs
are
additional
conditions
which
may
supplement
effluent
limitations
in
NPDES
permits.
Under
section
402(
a)(
1)
of
the
CWA,
BMPs
may
be
imposed
when
the
Administrator
determines
that
such
conditions
are
necessary
to
carry
out
the
provisions
of
the
Act.
See
40
CFR
122.44(
k).
CWA
section
304(
e)
authorizes
EPA
to
promulgate
BMPs
as
effluent
limitations
guidelines.
NPDES
rules
provide
for
BMPs
when:
authorized
under
section
304(
e)
of
the
CWA
for
the
control
of
toxic
pollutants
and
hazardous
substances;
numeric
limitations
are
infeasible;
or,
the
practices
are
reasonably
necessary
to
achieve
effluent
limitations
and
standards
to
carry
out
the
purposes
of
the
CWA.
In
addition,
each
NPDES
or
state
equivalent
permit
for
a
wastewater
treatment
system
must
contain
operation
and
maintenance
requirements
to
reduce
the
risk
of
discharges.
40
CFR
122.41(
e).

Additionally,
some
wastewater
is
pretreated
prior
to
discharge
to
a
permitted
wastewater
treatment
facility.
The
CWA
authorizes
EPA
to
establish
pretreatment
standards
for
pollutants
that
pass
through
or
interfere
with
the
operation
of
POTWs.
The
General
Pretreatment
Regulations
(GPR),
which
set
for
the
framework
for
the
implementation
of
categorical
pretreatment
standards,
are
found
at
40
CFR
part
403.
The
GPR
prohibit
a
user
from
introducing
a
pollutant
into
a
POTW
which
causes
pass
through
or
interference.
40
CFR
403.5(
a)(
1).
More
specifically,
the
GPR
also
prohibit
the
introduction
into
of
POTW
of
"petroleum,
oil,
nonbiodegradable
cutting
oil,
or
products
of
mineral
oil
origin
in
amounts
that
will
cause
interference
or
pass
through.
40
CFR
403.5(
b)(
6).
EPA
believes
that
the
GPR
and
the
more
specific
categorical
pretreatment
standards,
some
of
which
allow
indirect
dischargers
to
adopt
a
BMP
as
an
alternative
way
to
meet
pretreatment
standards,
will
work
to
prevent
the
discharge
of
oil
from
wastewater
treatment
systems
into
navigable
waters
or
adjoining
shorelines
by
way
of
a
POTW.

However,
if
a
wastewater
facility
or
part
thereof
is
used
for
the
purpose
of
storing
oil,
then
there
is
no
exemption,
and
its
capacity
must
be
counted
as
part
of
the
storage
capacity
of
the
facility.
Any
oil
storage
capacity
associated
with
or
incidental
to
these
wastewater
treatment
facilities
or
parts
thereof
continues
to
be
subject
to
part
112.
At
permitted
wastewater
treatment
facilities,
storage
capacity
includes
bulk
storage
containers,
hydraulic
equipment
associated
with
the
treatment
process,
containers
used
to
store
oil
which
feed
an
emergency
generator
associated
with
wastewater
62
treatment,
and
slop
tanks
or
other
containers
used
to
store
oil
resulting
from
treatment.
Some
flow
through
treatment
such
as
oil/
water
separators
have
a
storage
capacity
within
the
treatment
unit
itself.
This
storage
capacity
is
subject
to
the
rule.
An
example
of
a
wastewater
treatment
unit
that
functions
as
storage
is
a
treatment
unit
that
accumulates
oil
and
performs
no
further
treatment,
such
as
a
bulk
storage
container
used
to
separate
oil
and
water
mixtures,
in
which
oil
is
stored
in
the
container
after
removal
of
the
water
in
the
separation/
treatment
process.

We
do
not
consider
wastewater
treatment
facilities
or
parts
thereof
at
an
oil
production,
oil
recovery,
or
oil
recycling
facility
to
be
wastewater
treatment
for
purposes
of
this
paragraph.
These
facilities
generally
lack
NPDES
or
state­
equivalent
permits
and
thus
lack
the
protections
that
such
permits
provide.
Production
facilities
are
normally
unmanned
and
therefore
lack
constant
human
oversight
and
inspection.
Produced
water
generated
by
the
production
process
normally
contains
saline
water
as
a
contaminant
in
the
oil,
which
might
aggravate
environmental
conditions
in
addition
to
the
toxicity
of
the
oil
in
the
case
of
a
discharge.

Additionally,
the
goal
of
an
oil
production,
oil
recovery,
or
oil
recycling
facility
is
to
maximize
the
production
or
recovery
of
oil,
while
eliminating
impurities
in
the
oil,
including
water,
whereas
the
goal
of
a
wastewater
treatment
facility
is
to
purify
water.
Neither
an
oil
production
facility,
nor
an
oil
recovery
or
oil
recycling
facility
treats
water,
instead
they
treat
oil.
For
purposes
of
this
exemption,
produced
water
is
not
considered
wastewater
and
treatment
of
produced
water
is
not
considered
wastewater
treatment.
Therefore,
a
facility
which
stores,
treats,
or
otherwise
uses
produced
water
remains
subject
to
the
rule.
At
oil
drilling,
oil
production,
oil
recycling,
or
oil
recovery
facilities,
treatment
units
subject
to
the
rule
include
open
oil
pits
or
ponds
associated
with
oil
production
operations,
oil/
water
separators
(gun
barrels),
and
heater/
treater
units.
Open
oil
pits
or
ponds
function
as
another
form
of
bulk
storage
container
and
are
not
used
for
wastewater
treatment.
Open
oil
pits
or
ponds
also
pose
numerous
environmental
risks
to
birds
and
other
wildlife.

Examples
of
wastewater
treatment
facilities
or
parts
thereof
used
to
meet
a
part
112
requirement
include
an
oil/
water
separator
used
to
meet
any
SPCC
requirement.
Oil/
water
separators
used
to
meet
SPCC
requirements
include
oil/
water
separators
used
as
general
facility
secondary
containment
(i.
e.,
§112.7(
c),
secondary
containment
requirements
for
loading
and
unloading
(i.
e.,
§112.7(
h)),
and
for
facility
drainage
(i.
e.,
§112.8(
b)
or
§112.9(
b)).

Whether
a
wastewater
treatment
facility
or
part
thereof
is
used
exclusively
for
wastewater
treatment
(i.
e.,
not
storage
or
other
use
of
oil)
or
used
to
satisfy
a
requirement
of
part
112
will
often
be
a
facility
specific
determination
based
on
the
activity
associated
with
the
facility
or
part
thereof.
Only
the
portion
of
the
facility
(except
at
an
oil
production,
oil
recovery,
or
oil
recycling
facility)
used
exclusively
for
wastewater
treatment
and
not
used
to
meet
any
part
112
requirement
is
exempt
from
part
112.
Storage
or
use
of
oil
at
such
a
facility
will
continue
to
be
subject
to
part
112.
63
Although
we
exempt
wastewater
treatment
facilities
or
parts
thereof
from
the
rule
under
certain
circumstances,
a
mixture
of
wastewater
and
oil
still
is
"oil"
under
the
statutory
and
regulatory
definition
of
the
term
(33
USC
1321(
a)(
1)
and
40
CFR
110.2
and
112.2).
Thus,
while
we
are
excluding
from
the
scope
of
the
rule
certain
wastewater
treatment
facilities
or
parts
thereof,
a
discharge
of
wastewater
containing
oil
to
navigable
waters
or
adjoining
shorelines
in
a
"harmful
quantity"
(40
CFR
Part
110)
is
prohibited.
Thus,
to
avoid
such
discharges,
we
would
expect
owners
or
operators
to
comply
with
the
applicable
permitting
requirements,
including
best
management
practices
and
operation
and
maintenance
provisions.
64
Category
V:
Definitions
­
§112.2
Background:
In
§112.2
of
the
current
rule
are
found
definitions
for
terms
used
in
40
CFR
part
112.
In
§112.2
of
the
1991,
we
proposed
revisions
of
certain
definitions,
adding
some
new
definitions,
and
removing
others.
We
also
proposed
to
move
the
definitions
of
oil
production
facilities
(onshore)
and
oil
drilling,
production,
or
workover
facilities
(offshore)
from
§112.7(
e)(
5)(
i)
and
112.7(
e)(
7)(
i),
respectively,
to
§112.2.

V­
1
Breakout
tank
Background:
In
§112.2(
a)
of
the
1991
proposal,
we
proposed
to
define
breakout
tank
to
distinguish
between
facilities
regulated
by
the
U.
S.
Department
of
Transportation
(DOT)
and
EPA.
(Breakout
tanks
fall
under
DOT
jurisdiction;
we
regulate
facilities
with
bulk
storage
tanks.)
Breakout
tanks
are
used
either
to
compensate
for
pressure
surges
or
control
and
maintain
pressure
through
pipelines.
In
§112.2
of
the
final
rule,
we
adopted
a
modified
version
of
DOT's
49
CFR
part
195
definition,
and
defined
a
breakout
tank
as
"a
container
used
to
relieve
surges
in
an
oil
pipeline
system
or
to
receive
and
store
oil
transported
by
a
pipeline
for
reinjection
and
continued
transportation
by
pipeline."

Comments:
Support
for
a
definition.
Support
for
including
a
definition
of
breakout
tank
in
part
112.
(94,
95,
102)

DOT
definition.
"Valvoline
supports
the
inclusion
of
a
definition
of
`breakout
tank'
in
the
proposed
regulations.
However,
in
light
of
the
fact
that
this
is
a
transportation­
related
term,
the
definition
should
be
identical
to
that
contained
in
40
CFR
§195.2.
An
arbitrary
change
to
this
definition
will
result
in
wide
spread
confusion
regarding
what
constitutes
a
breakout
tank
and
which
definition
takes
precedence.
"
(77,
95,
101,
102,113,
121,
153,
173,
175)
We
should
consider
providing
guidance
on
when
each
agency
regulates
certain
tanks.
(94)
Two
different
definitions
would
result
in
duplicative
regulation
of
certain
tanks.
(102,
153)

Response:
On
the
suggestion
of
commenters,
EPA
has
adopted
a
modified
version
of
the
DOT
definition
in
49
CFR
195.2.
This
revision
promotes
consistency
in
the
DOT
and
EPA
definitions
to
aid
the
regulators
and
regulated
community.
We
modified
the
DOT
definition
by
substituting
the
word
"oil"
for
"hazardous
liquid,"
because
our
rules
apply
only
to
oil.
We
also
use
in
the
definition
the
term
"container"
rather
than
just
"tank"
to
cover
any
type
of
container.
This
terminology
is
consistent
with
other
terminology
used
in
this
rule.

A
breakout
tank
that
is
used
only
to
relieve
surges
in
an
oil
pipeline
system
or
to
receive
and
store
oil
transported
by
a
pipeline
for
reinjection
and
continued
transportation
by
pipeline
is
subject
only
to
DOT
jurisdiction.
When
that
same
breakout
tank
is
used
for
other
purposes,
such
as
a
process
tank
or
as
a
bulk
storage
container,
it
is
no
longer
solely
within
the
definition
of
breakout
tank,
and
may
be
subject
to
EPA
or
other
jurisdiction
with
the
new
use.
See
also
the
discussion
of
§112.1(
d)(
1)(
ii)
in
the
65
preamble
to
today's
rule.
EPA
and
DOT
also
signed
a
joint
memorandum
dated
February
4,
2000,
clarifying
regulatory
jurisdiction
on
breakout
tanks.
That
memorandum
is
available
to
the
public
upon
request.
It
is
also
available
on
our
website
at
http://
www.
epa.
gov/
oilspill
under
the
"What's
New"
section.

V­
2
Bulk
storage
container
Background:
In
1991,
we
proposed
defining
the
term
bulk
storage
tank
to
clarify
the
distinction
between
facilities
regulated
by
DOT
and
EPA.
The
proposed
definition
was
originally
for
"bulk
storage
tank."

Comments:
We
should
exclude
electrical
equipment
from
the
bulk
storage
tank
definition
because
such
equipment
does
not
consume
or
store
oil.
(41,
125,
134,
164)

Response:
We
agree
that
electrical
equipment
is
not
bulk
storage,
and
have
revised
the
definition
of
bulk
storage
container
to
specifically
exclude
oil­
filled
electrical,
operating,
or
manufacturing
equipment.
While
such
equipment
is
not
bulk
storage,
it
is
subject
to
the
general
requirements
of
the
rule
in
§112.7.

V
­3Bunkered
tank
Background:
We
proposed
this
definition
in
1991
to
clarify
that
bunkered
tanks
are
a
subset
of
partially
buried
tanks,
and
as
such,
subject
to
part
112
as
aboveground
tanks.

Comments:
The
definition
is
"undecipherable
and
should
be
rewritten."
The
definition
should
be,
"Bunkered
tank
means
a
partially
buried
tank,
the
portion
of
which
lies
above
grade
is
covered
with
earth,
sand,
gravel,
asphalt,
or
other
material."
(121)

Response:
EPA
agrees
that
the
commenter's
proposed
definition
is
clearer,
and
we
have
used
it
with
a
slight
editorial
change.

Editorial
change.
We
added
a
sentence
to
the
definition
noting
that
bunkered
tanks
are
a
subset
of
aboveground
storage
containers
for
purposes
of
this
part.

V­
4
Completely
buried
tank
Background:
We
proposed
in
§112.2(
v)
to
define
an
underground
storage
tank
(UST)
as
any
tank
completely
covered
with
earth.
We
noted
that
tanks
in
subterranean
vaults,
bunkered
tanks,
or
partially
buried
tanks
are
aboveground
storage
containers
under
part
112.
We
have
editorially
changed
"underground
storage
tank"
to
"completely
buried
tank"
to
distinguish
those
tanks
from
the
"underground
storage
tank"
definition
in
part
280,
which
is
broader
than
our
definition.

Comments:
Consistency
with
part
280
definition.
The
part
112
definition
of
an
UST
should
be
consistent
with
the
part
280
definition.
(57,
78,
90,
109,
111,
116,
167,
180,
66
182,
187).
The
differences
in
the
definitions
in
parts
112
and
280
would
confuse
the
regulated
community.
(57,
90,
111)
We
should
define
an
UST
as
any
tank
that
is
completely
below
grade,
and
completely
covered
with
earth,
including
vaults,
bunkered
tanks,
or
partially
buried
tanks.
(102,
121)
The
part
280
UST
definition
is
more
consistent
with
our
statutory
authority
under
the
Clean
Water
Act
(CWA)
than
the
part
112
definition.
(182)
Our
proposed
definition
is
too
narrow,
because
it
includes
only
completely
buried
tanks.
(67,
72,
102,
106,
133,
175,
182)

New
term
needed.
"Alyeska
appreciates
that
EPA
requires
a
different
definition
for
underground
tanks
than
40
CFR
Part
280.
However,
it
is
very
confusing
for
the
regulated
community
to
have
two
different
definitions
to
the
term
`underground
storage
tank.
'
EPA
should
identify
tanks
that
it
wishes
to
exclude
from
SPCC
Plan
regulations
by
some
other
term
to
avoid
this
confusion.
EPA
invites
inadvertent
non­
compliance
when
it
uses
a
term
which
has
two
different
definitions."
(27,
77,
87)

Bunkered
tanks,
partially
buried
tanks.
We
should
consider
bunkered
tanks
and
partially
buried
tanks
as
aboveground
storage
tanks
under
part
112.
We
should
regulate
a
tank
under
part
112
as
an
aboveground
tank
only
if
it
is
not
regulated
under
part
280.
(190)

Vaulted
tanks.
"In
some
locations
(e.
g.,
New
York
City),
subterranean
vaults
are
the
method
of
secondary
containment
specified
for
underground
storage
tanks.
The
vault
and
tank
in
such
cases
are
usually
completely
covered
by
earth
and,
thus,
pose
no
threat
to
the
waters
of
the
US.
Such
tanks
should
be
exempted
from
the
SPCC
requirements."
(33,
67,
72,
121,
133,
175)

Response:
Support
for
proposal.
We
appreciate
commenter
support.

Consistency
with
part
280
definition.
We
disagree
that
the
scope
of
the
part
112
exclusion
for
underground
tanks
should
be
consistent
with
the
scope
of
the
definition
of
"underground
storage
tank"
in
part
280.
The
programs
are
designed
for
different
purposes,
therefore,
the
definitions
used
will
necessarily
differ.
To
eliminate
confusion
with
the
part
280
definition,
we
have
changed
the
proposed
part
112
definition
of
"underground
storage
tank"
to
"completely
buried
tank"
in
this
final
rule.

Part
280
includes
within
its
UST
definition
tanks
which
have
a
volume
up
to
ninety
percent
above
the
surface
of
the
ground,
which
are
considered
aboveground
tanks
for
part
112
purposes.
Part
280
also
regulates
underground
storage
tanks
containing
hazardous
substances,
while
the
SPCC
program
regulates
only
facilities
storing
or
using
oil
as
defined
in
CWA
section
311.
The
SPCC
program
also
regulates
other
types
of
containers
and
facilities
which
part
280
excludes,
such
as:
tanks
used
for
storing
heating
oil
for
consumptive
use
on
the
premises
where
stored;
certain
pipeline
complexes
where
oil
is
stored;
and,
oil­
water
separators.
67
Other
completely
buried
tanks
excluded
from
the
part
280
UST
definition.
Tanks
in
underground
rooms
or
above
the
floor
surface,
or
in
other
underground
areas
such
as
basements,
cellars,
mine
workings,
drifts,
shafts,
or
tunnels
are
also
not
considered
USTs
for
purposes
of
the
part
280
definition.
The
purpose
of
the
part
112
definition
is
to
clarify
that
these
are
tanks
that
are
technically
underground
but
that,
in
a
practical
sense,
are
no
different
from
aboveground
tanks.
They
are
situated
so
that,
to
the
same
extent
as
tanks
aboveground,
physical
inspection
for
leaks
is
possible.
Also,
some
of
these
tanks
are
designed
such
that
in
case
of
a
discharge,
oil
would
escape
to
the
environment,
a
result
which
our
program
seeks
to
prevent.

Editorial
changes
and
clarifications.
The
words
"completely
below
grade
and...."
were
added
to
the
first
sentence
of
the
definition.
The
purpose
of
that
revision
was
to
distinguish
completely
buried
tanks
from
partially
buried
and
bunkered
tanks,
which
break
the
grade
of
the
land,
but
are
not
completely
below
grade.
We
further
clarify
that
such
tanks
may
be
covered
not
only
with
earth,
but
with
sand,
gravel,
asphalt,
or
other
material.
The
clarification
brings
the
definition
into
accord
with
the
coverings
noted
in
the
definition
of
"bunkered
tank."
In
the
second
sentence,
the
word
"subterranean"
was
deleted
from
"subterranean
vaults"
because
all
vaulted
tanks,
whether
subterranean
or
aboveground,
are
counted
as
aboveground
tanks
for
purposes
of
this
rule.

Bunkered
tanks,
partially
buried
tanks.
We
disagree
that
vaulted
tanks,
partially
buried
tanks,
and
bunkered
tanks
should
be
considered
completely
buried
tanks,
and
therefore
excluded
from
SPCC
provisions.
Such
tanks
may
suffer
damage
caused
by
differential
corrosion
of
buried
and
non­
buried
surfaces
greater
than
completely
buried
tanks,
which
could
cause
a
discharge
as
described
in
§112.1(
b).

Vaulted
tanks.
Aboveground
vaulted
tanks
are
clearly
ASTs.
Subterranean
vaulted
tanks
are
also
ASTs
because
they
are
not
completely
buried.
While
subterranean
vaulted
tanks
may
be
completely
below
grade,
they
are
not
completely
covered
with
earth,
sand,
gravel,
asphalt,
or
other
material.
Therefore,
because
of
their
design,
they
pose
a
threat
of
discharge
into
the
environment,
and
are
excluded
from
our
definition
of
completely
buried
tank.
Subterranean
vaulted
tanks
are
also
excluded
from
the
part
280
UST
definition
of
underground
tank
if
the
storage
tank
is
situated
upon
or
above
the
surface
of
the
floor
in
an
underground
area
providing
enough
space
for
physical
inspection
of
the
exterior
of
the
tank.
Therefore,
if
subterranean
tanks
were
excluded
from
our
definition
of
completely
buried
tank,
they
would
likely
not
be
regulated
at
all,
and
thereby
be
likely
to
pose
a
greater
threat
to
the
environment.

V­
5
Discharge
Background:
In
proposed
§112.2(
e),
we
suggested
modification
of
the
definition
of
discharge
to
reflect
changes
in
the1978
amendments
to
the
CWA.
68
Comments:
Section
402
discharges.
We
should
exclude
discharges
regulated
under
CWA
section
402
to
eliminate
duplicative
regulations.
(67,
125)

Imminent
danger.
"Recommend
that
the
definition
of
discharge
include
that
there
is
at
least
an
eminent
danger
that
the
spilled
material
reach
a
`navigable
waterway'.
Otherwise,
it
is
too
broad
and
would
cover
even
spills
within
secondary
containment."
(28,
31,
101,
113,
121,
165,
L15)

Discharges
within
secondary
containment
or
the
facility.
We
should
define
discharge
to
include
a
spill,
leak,
or
other
release
that
reaches
navigable
waters.
A
spill
or
leak
will
not
necessarily
result
in
a
discharge
to
navigable
waters.
(39,
121,
L12)
The
proposed
definition
seems
vague,
because
it
is
"unlikely
to
operationally
prevent
all
spilling
or
leaking."
It
is
unclear,
for
example,
whether
a
drop
of
oil
that
falls
"onto
the
outside
casing
of
a
tank
during
refilling
would
be
considered
a
discharge,
even
if
the
oil
did
not
reach
the
ground."
The
definition
is
inconsistent
with
part
112.
(115)
Our
proposed
definition
appears
to
"regulate
more
than
the
quality
of
navigable
waters."
(L12)

Response:
Section
402
discharges.
We
agree
that
we
should
not
regulate
discharges
under
section
402
of
the
Act,
and
in
the
final
rule,
we
have
adopted
the
proposed
definition
of
a
discharge,
which
accomplishes
that
aim.

Foreseeable
or
chronic
point
source
discharges
that
are
permitted
under
section
402
of
the
CWA,
and
that
are
either
due
to
causes
associated
with
the
manufacturing
or
other
commercial
activities
in
which
the
discharger
is
engaged
or
due
to
the
operation
of
the
treatment
facilities
required
by
the
NPDES
permit,
are
to
be
regulated
under
the
NPDES
program.
Other
oil
discharges
in
reportable
quantities
are
subject
to
the
requirements
of
section
311
of
the
CWA.
Such
spills
or
discharges
are
governed
by
section
311
even
where
the
discharger
holds
a
valid
and
effective
NPDES
permit
under
CWA
section
402.
Therefore,
a
discharge
of
oil
to
a
publicly­
owned
treatment
work
(POTW)
would
not
be
a
discharge
under
the
§112.2
definition
if
the
discharge
is
in
compliance
with
the
provisions
of
the
permit;
or
resulted
from
a
circumstance
identified
and
reviewed
and
made
a
part
of
the
public
record
with
respect
to
a
permit
issued
or
modified
under
section
402;
or
if
it
were
a
continuous
or
anticipated
intermittent
discharge
from
a
point
source,
identified
in
a
permit
or
permit
application
under
section
402,
which
is
caused
by
events
occurring
within
the
scope
of
relevant
operating
or
treatment
systems.
33
U.
S.
C.
1321(
a)(
2);
40
CFR
117.12.
Otherwise,
the
discharge
is
subject
to
the
provisions
of
section
311
of
the
CWA
as
well
as
the
unpermitted
discharge
prohibition
of
section
301(
a)
of
the
CWA.
33
U.
S.
C.
1311(
a).

Imminent
danger.
A
discharge
as
described
in
§112.1(
b)
need
not
reach
the
level
of
an
imminent
danger
to
affected
lands,
waters,
or
resources
to
be
a
discharge.

Discharges
within
secondary
containment
or
the
facility.
We
agree
that
we
should
define
discharge
to
include
a
spill,
leak,
or
other
release
that
reaches
navigable
waters,
and
have
done
so.
We
define
a
discharge
to
include
any
spilling,
leaking,
pumping,
emitting,
emptying,
or
dumping
of
oil,"
with
certain
exclusions
pertinent
to
section
402
69
of
the
CWA.
We
also
agree
that
a
spill,
leak,
or
other
type
of
discharge
will
not
necessarily
result
in
a
discharge
to
navigable
waters.
A
discharge
includes
any
spilling,
leaking,
pumping,
pouring,
emitting,
emptying,
or
dumping
of
any
amount
of
oil
no
matter
where
it
occurs.
It
may
not
be
a
reportable
discharge
under
40
CFR
part
110
if
oil
never
escapes
the
secondary
containment
at
the
facility
and
is
promptly
cleaned
up.
If
the
discharge
escapes
secondary
containment,
it
may
become
a
discharge
as
described
in
§112.1(
b),
and
if
that
happens,
the
discharge
must
then
be
reported
to
the
National
Response
Center.

V­
6
Facility
Background:
In
§112.2(
f)
of
the
1991
proposal,
we
proposed
to
define
the
term
facility
based
on
the
definition
in
the
1971
MOU
between
EPA
and
DOT.
(See
40
CFR
part
112,
Appendix
A.)
We
proposed
to
define
a
facility
as
"any
mobile
or
fixed,
onshore
or
offshore
building,
structure,
installation,
equipment,
pipe,
or
pipeline
used
in
oil
well
drilling
operations,
oil
production,
oil
refining,
oil
storage,
and
waste
treatment."
We
noted
that
the
extent
of
a
facility
may
depend
on
several
site­
specific
factors,
including,
but
not
limited
to,
the
ownership
or
operation
of
buildings,
structures,
equipment,
and
pipelines
on
the
same
site
and
the
types
of
activities
at
the
site.

Comments:
Facility
boundaries.
"The
definition
of
facility
are
[sic]
too
broad.
Not
all
buildings
on
an
oil
production
lease
are
in
contact
with
oil,
nor
are
all
pipeline
structures,
installations,
or
equipment.
Their
operation
may
in
no
way
affect
the
possibility
of
an
oil
spill,
and
they
should
not
have
to
be
addressed
in
a
SPCC
plan
as
inclusion
in
this
definition
would
require.
The
same
is
true
for
waste
treatment
activities.
"
(31,
101,
113,
160,
165,
188,
L15)
"The
definition
of
facility
is
ambiguous.
Is
a
facility
the
petroleum
storage
site,
or
...
a
single
tank
at
a
site?"
(111,
188)

Pipes
and
piping.
"Rather,
the
definition
contemplates
a
fixed
structure,
or
unit,
which
serves
a
purpose
at
the
place
where
it
is
fixed.
...
We
suggest
that
EPA
clarify
the
factors
which
will,
rather
than
may,
define
the
boundaries
of
a
facility,
specifically
with
regard
to
piping
or
pipelines
which
may
extend
past
the
physical
boundaries
of
the
facility."
(188)

Buried
pipelines,
gathering
lines,
flowlines,
military
housing
units,
waste
treatment
equipment.
"Also,
by
including
oil
gathering
lines
in
the
facility
definition,
the
size
and
extent
of
oil
production
facilities
is
multiplied
at
least
a
thousand­
fold.
No
secondary
containment
is
possible
for
these
lines...."
(31)
"Based
on
the
proposed
definition,
it
is
unclear
whether
the
regulation
requires
that
all
oil
distribution
and
movement
facilities
be
identified,
such
as
buried
pipelines,
for
volume
storage
estimates.
This
too
presents
a
task
which
cannot
readily
be
satisfied
at
many
mining
operations."
(35,
28,
31,
58,
71,
101,
113,
165,
L15).

Military
housing.
We
should
amend
the
proposed
definition
to
ensure
that
part
112
does
not
cover
military
housing
units.
Each
such
unit
may
store
fuel
oil
in
a
250­
gallon
tank.
(L29)
70
Waste
treatment.
We
should
not
include
the
term
waste
treatment
in
the
part
112
definition
of
a
facility,
unless
the
waste
treated
is
from
oil
drilling
or
production
operations.
(L24,
31)

Electrical
or
operational
equipment.
"Clearly,
electrical
equipment
is
not
used
in
well
drilling
operations,
oil
production,
oil
refining,
oil
storage,
or
waste
treatment.
As
such,
oil­
filled
electrical
equipment
is
not
a
`facility'
under
the
proposed
SPCC
regulations
and
not
subject
to
the
requirements
established
therein."
(189)
Mobile
or
fixed
facilities.
"CCIRT
is
concerned
that
the
proposed
definition
is
overly
broad,
because
it
encompasses
mobile
as
well
as
fixed,
structures
and
equipment.
CCIRT
considers
this
expansion
of
the
definition
to
be
inappropriate.
...
Conceivably,
a
SPCC
Plan
for
a
mobile
`facility'
would
have
to
be
amended
each
time
the
mobile
equipment
is
moved.
This
is
likely
to
be
an
unworkable
requirement.
For
these
reasons,
mobile
equipment
should
not
be
considered
a
facility
for
purposes
of
SPCC
regulations."
(188)

Response:
We
disagree
that
the
definition
is
too
broad.
It
includes
the
necessary
elements
of
what
may
be
a
"facility."
If
one
of
those
elements
is
not
related
to
oil
well
drilling
operations,
oil
production,
oil
refining,
oil,
storage,
and
waste
treatment,
or
in
which
oil
is
used
at
the
site,
it
is
not
part
of
the
facility.

Facility
boundaries.
A
facility
includes
any
building,
structure,
installation,
equipment,
pipe,
or
pipeline
in
oil
well
drilling
operations,
oil
production,
oil
refining,
oil
storage,
and
waste
treatment,
or
in
which
oil
is
used
at
a
site,
whether
it
is
mobile
or
fixed.
It
may
also
include
power
rights
of
way
connected
to
the
facility.
We
also
clarify
that
a
vessel
or
a
public
vessel
is
not
a
facility
or
part
of
a
facility.
The
extent
of
the
facility
will
vary
according
to
the
circumstances
of
the
site.
It
may
be
as
small
as
a
single
container,
or
as
large
as
all
of
the
structures
and
buildings
on
a
site.
Some
specific
factors
to
use
in
determining
the
extent
of
a
facility
may
be
the
ownership
or
operation
of
those
buildings,
structures,
equipment,
installations,
pipes
or
pipelines,
or
the
types
of
activities
being
carried
on
at
the
facility.

Electrical
or
operational
equipment.
We
disagree
with
commenters
who
maintained
that
electrical
equipment
"using"
oil,
as
opposed
to
"storing"
it,
should
not
fall
within
the
definition
of
"facility"
in
part
112.
Section
311(
j)(
1)(
C)
of
the
CWA,
which
authorizes
EPA
to
promulgate
the
SPCC
rule,
does
not
distinguish
between
the
storage
and
the
usage
of
oil.
The
section
simply
authorizes
EPA,
as
delegated
by
the
President,
to
establish
"requirements
to
prevent
discharges
of
oil
...
from
onshore
and
offshore
facilities,
and
to
contain
such
discharges...."
33
U.
S.
C.
1321(
j)(
1)(
C).
Nor
do
the
definitions
of
"onshore
facility"
or
"offshore
facility"
in
sections
311(
a)(
10)
of
the
CWA
distinguish
between
the
use
or
storage
of
oil.
Although
the
definition
of
"facility"
in
section
1001(
9)
of
the
OPA
is
limited
by
the
"purpose"
of
the
facility,
no
such
limitation
appears
in
CWA
section
311.
Moreover,
EPA
believes
that
although
much
of
the
electrical
equipment
may
arguably
"use"
oil,
in
effect
the
oil
is
"stored"
in
the
equipment
because
it
remains
in
the
equipment
for
such
long
time
frames.
We
added
language
to
the
definition
to
clarify
that
such
types
of
equipment
are
facilities
subject
to
the
SPCC
71
rule
whether
they
are
storing
or
using
oil.
Therefore,
we
revised
the
definition
to
include
the
words
"or
in
which
oil
is
used."
However,
we
note
that
a
facility
which
contains
only
electrical
equipment
is
not
a
bulk
storage
facility.

Buried
pipelines,
gathering
lines,
flowlines,
military
housing
units,
waste
treatment
equipment.
Buried
pipelines
that
carry
oil
at
mining
sites
are
part
of
a
facility
unless
they
are
permanently
closed
as
defined
in
§112.2.
Such
pipelines
may
otherwise
be
the
source
of
a
discharge
as
described
in
§112.1(
b).
Likewise,
the
same
rationale
applies
to
gathering
lines
and
flowlines,
military
housing
units,
and
waste
treatment
equipment.
Note
that
any
facility
or
part
thereof
used
exclusively
for
wastewater
treatment
and
not
to
satisfy
any
part
112
requirement
is
exempted
from
the
rule.
The
production,
recovery,
or
recycling
of
oil
is
not
considered
wastewater
treatment
for
purposes
of
the
rule.
See
§112.1(
d)(
6).

While
such
gathering
lines,
flowlines,
and
waste
treatment
equipment
are
subject
to
secondary
containment
requirements,
the
appropriate
method
of
secondary
containment
is
an
engineering
question.
Double­
walled
piping
may
be
an
option,
but
is
not
required
by
these
rules.
The
owner
or
operator
and
Professional
Engineer
certifying
the
Plan
should
consider
whether
pursuant
to
good
engineering
practice,
double­
walled
piping
is
the
appropriate
method
of
secondary
containment
according
to
good
engineering
practice.
In
determining
whether
to
install
double­
walled
piping
versus
an
alternative
method
of
secondary
containment,
you
could
consider
such
factors
as
the
additional
effectiveness
of
double­
walled
piping
in
preventing
discharges,
the
technical
aspects
of
cathodically
protecting
any
buried
double­
walled
piping
system,
the
cost
of
installing
double­
walled
pipe,
and
the
potential
fire
and
safety
hazards
of
double­
walled
pipes.
Earthen
or
natural
structures
may
be
acceptable
if
they
contain
and
prevent
discharges
as
described
in
§112.1(
b),
including
containment
that
prevents
discharge
of
oil
through
groundwater
that
might
cause
a
discharge
as
described
in
§112.1(
b).
What
is
practical
for
one
facility,
however,
might
not
work
for
another.

We
also
disagree
with
the
argument
that
because
the
installation
of
structures
and
equipment
to
prevent
discharges
around
gathering
lines
and
flowlines
may
not
be
practicable,
EPA
will
be
flooded
with
contingency
plans.
First
of
all,
secondary
containment
may
be
practicable.
In
§112.7(
c),
we
list
sorbent
materials,
drainage
systems,
and
other
equipment
as
possible
forms
of
secondary
containment
systems.
We
realize
that
in
many
cases,
secondary
containment
may
not
be
practicable.
If
secondary
containment
is
not
practicable,
you
must
provide
a
contingency
plan
in
your
SPCC
Plan
following
the
provisions
of
part
109,
and
otherwise
comply
with
§112.7(
d).
We
have
deleted
the
proposed
1993
provision
that
would
have
required
you
to
provide
contingency
plans
as
a
matter
of
course
to
the
Regional
Administrator.
Therefore,
you
will
rarely
have
to
submit
a
contingency
plan
to
EPA.
The
contingency
plan
you
do
provide
in
your
SPCC
Plan
when
secondary
containment
is
not
practicable
for
flowlines
and
gathering
lines
should
rely
on
strong
maintenance,
corrosion
protection,
testing,
recordkeeping
and
inspection
procedures
to
prevent
and
quickly
detect
discharges
from
such
lines.
It
should
also
provide
for
the
quick
availability
of
response
equipment.
72
Mobile
or
fixed
facilities.
Either
mobile
or
fixed
equipment
might
be
the
source
of
a
discharge
as
described
in
§112.1(
b),
and
therefore
both
are
included
within
the
definition
of
"facility."
Section
112.
3(
c)
of
this
rule
already
provides
that
it
is
not
necessary
to
amend
your
Plan
each
time
a
mobile
facility
moves
to
a
new
site.

V
­7
Navigable
waters
Background:
In
§112.2(
g)
of
the
1991
proposal,
we
proposed
to
revise
the
definition
of
navigable
waters
to
conform
to
the
definition
in
40
CFR
part
110.

Comments:
Definition
too
broad,
clarification
needed.
(31,
35,
64,
73,
89,
101,
106,
113,
165,
174,
186,
L15,
L23)
"We
have
two
concerns
with
this
proposal.
First,
we
do
not
believe
EPA
should
expand
its
jurisdictional
authority
since
the
jurisdiction
provided
under
traditional
notions
of
navigability
and
contained
in
the
existing
regulations
is
sufficient
to
protect
the
Nation's
waters
from
bulk
oil
contamination.
...
Second,
under
§404
of
the
Clean
Water
Act,
EPA
interprets
the
predicate
jurisdictional
trigger,
`waters
of
the
United
States,
'
in
an
expansive
manner
to
include
artificial
and
isolated
wetlands."
Wetland
delineation
is
quite
complex,
and
often
includes
areas
that
are
not
adjacent
to
navigable
waters,
nor
even
tributary
or
in
any
connected
to
navigable
waters."
(35)
"We
feel
that
compliance
with
these
regulations
could
be
more
easily
obtained
if
this
definition
was
simplified."
(94,
111,
166)
"Using
this
interpretation,
nearly
all
facilities
would
be
located
less
than
500
feet
from
navigable
waters.
Some
guidance
as
to
the
correct
interpretation
of
this
issue
would
be
helpful."
(107,
79,
167,
186,
L17)

Navigability.
"The
definition
of
navigable
waters
should
be
revised
to
match
what
Congress
originally
intended
­
waters
that
a
boat
of
some
kind
(even
a
canoe)
can
travel
on
at
all
times
of
the
year."
(31,
73,
101,
106,
113,
165,
L15)
"Navigable
Waters
is
defined
in
extremely
broad
terms
under
the
proposed
definition.
While
broad
statutory
references
are
made
elsewhere
in
the
proposed
rule,
no
specific
authority,
legislative
or
judicial,
is
cited
or
identified
to
support
this
expansive
definition."
(64)

Risk.
"The
EPA's
emphasis
in
this
phase
of
the
SPCC
revisions
should
be
on
controlling
discharges
from
facilities
with
the
greatest
potential
to
discharge
harmful
quantities
of
oil
to
navigable
waters.
The
broad
applicability
of
the
proposed
SPCC
revisions
will
overwhelm
the
regulated
community."
(167)
"The
proposed
rule's
mention
of
discharges
into
or
upon
the
navigable
waters
of
the
United
States
together
with
the
extremely
broad
interpretation
of
`navigable
waters'
and
waters
which
flow
to
`navigable
waters'
could
result
in
application
of
this
rule
to
inland
agricultural
operations."
(L23)

Tributaries.
Asks,
"...(
A)
re
ditches
which
flow
miles
to
navigable
waters
considered
tributaries?"
(62)
"Since
the
EPA
considers
tributaries
to
navigable
water
(i.
e.,
rivers)
as
part
of
this
definition,
ultimately
any
size
stream,
including
those
which
may
be
only
intermittent,
would
be
subject
to
this
rule."
(89)
We
73
should
define
navigable
waters
as
"unobstructed
streams
that
free
flow
at
least
fourteen
consecutive
days
per
year."
(186)

Criteria.
The
definition
should
"include
specific
criteria
such
as
flow
volume."
(89,
156)

Maps.
"Due
to
the
broad
definition
of
navigable
waters,
how
is
an
operator
to
determine
what
is
navigable
water?
Because
this
is
such
a
confusing
issue,
an
operator
is
at
a
loss
to
determine
which
facilities
could
reasonably
be
expected
to
discharge
oil
upon
a
navigable
water.
Will
the
EPA
provide
maps
to
aid
in
this
determination?"
(28,
69,
79,
101)

Groundwater.
"...(
C)
ongress
intended
for
EPA
to
develop
SPCC
requirements
that
prevent
releases
to
groundwater,
in
addition
to
requirements
that
prevent
releases
to
navigable
waters.
Thus,
SPCC
regulations
should
be
rewritten
to
prevent
discharges
to
groundwater
in
addition
to
discharges
to
navigable
waters.
...
At
a
minimum,
proposed
section
112.1(
d)(
1)(
i)
should
contain
language
stating
that
clear
hydrologic
connections
between
groundwater
underlying
a
facility
and
navigable
waters
require
a
facility
to
develop
and
implement
an
SPCC
Plan."
(44)

Response:
Clarification
of
the
meaning
of
navigable
waters,
maps.
In
this
definition,
we
clarify
what
we
mean
by
navigable
waters
by
describing
the
characteristics
of
navigable
waters
and
by
listing
examples
of
navigable
waters.
We
also
note
in
the
definition
that
certain
waste
treatment
systems
are
not
navigable
waters.

Navigability,
legal
authority.
Navigable
waters
are
not
only
waters
on
which
a
craft
may
be
sailed.
Navigable
waters
include
all
waters
with
a
past,
present,
or
possible
future
use
in
interstate
or
foreign
commerce,
including
all
waters
subject
to
the
ebb
and
flow
of
the
tide.
Navigable
waters
also
include
intrastate
waters
which
could
affect
interstate
or
foreign
commerce.
The
case
law
supports
a
broad
definition
of
navigable
waters,
such
as
the
one
published
today,
and
that
definition
does
not
necessarily
depend
on
navigability
in
fact.

Tributaries.
For
the
reasons
stated
above,
tributaries
or
intermittent
streams
are
included
in
the
definition
of
navigable
waters,
and
it
would
therefore
be
inappropriate
to
limit
the
definition
to
unobstructed
streams
that
free
flow
at
least
fourteen
consecutive
days
a
year.

Maps.
We
are
unable
to
provide
a
map
to
identify
all
navigable
waters
because
not
all
such
waters
have
been
identified
on
a
map.
However,
the
rule
provides
guidelines
as
to
where
such
waters
may
be
found.

Groundwater.
EPA
agrees
with
the
commenter
that
groundwater
underlying
a
facility
that
is
directly
connected
hydrologically
to
navigable
waters
or
adjoining
shorelines
could
trigger
the
requirement
to
produce
an
SPCC
Plan
based
on
geographic
or
locational
aspects
of
the
facility.
74
V
­8
Offshore
facility
Background:
In
1991,
we
proposed
to
revise
the
definition
of
offshore
facility
to
conform
with
the
CWA
definition
in
section
311(
a)(
11)
and
the
National
Oil
and
Hazardous
Substances
Pollution
Contingency
Plan
(NCP)
definition
in
40
CFR
300.5.

Comments:
CWA
definition.
"Offshore
Facility
is
defined
in
an
ambiguous
and
circuitous
manner
in
the
proposed
rules.
Midway
through
the
proposed
definition,
the
unnecessarily
redundant
phrase
`and
any
facility
of
any
kind
that
is
subject
to
the
jurisdiction
of
the
United
States
and
is
located
in,
on,
or
under
any
other
waters'
is
included.
The
definition
in
the
CWA
is
better
and
clearer."
(64)

EPA
or
DOI
jurisdiction.
"We
note
that
if
the
definition
of
`offshore
facility'
in
section
1001(
22)
of
OPA
90
is
taken
in
context
with
the
definition
of
`navigable
waters'
proposed
for
40
CFR
112.
2(
g),
the
jurisdiction
for
many
facilities
(including
large
numbers
which
have
traditionally
been
subject
to
EPA
jurisdiction)
would
be
transferred
to
the
Department
of
Interior
(DOI)
by
E.
O.
12777."
(128)

Response:
CWA
definition.
EPA
agrees
with
the
commenter
urging
that
the
EPA
definition
track
the
statutory
definition.
The
part
112
definition,
except
for
minor
editorial
changes,
is
identical
to
the
CWA
definition.
There
is
no
difference
between
the
substance
of
the
part
112
definition
and
the
CWA
definition.

EPA
or
DOI
jurisdiction.
The
1994
Memorandum
of
Understanding
between
DOI,
DOT,
and
EPA
addresses
the
jurisdictional
issue
to
which
the
commenter
refers,
transferring
to
EPA
those
non­
transportation­
related
offshore
facilities
landward
of
the
coast
line.

V
­9
Oil
Background:
In
current
§112.2
we
define
oil
as
"oil
of
any
kind
or
in
any
form,
including,
but
not
limited
to,
petroleum,
fuel
oil,
sludge,
oil
refuse,
and
oil
mixed
with
wastes
other
than
dredged
spoil."
We
proposed
no
changes
in
the
definition
in
1991.
However,
in
the
1991
preamble,
we
explained
this
definition
includes
crude
oil
and
refined
petroleum
products,
as
well
as
non­
petroleum
oils
(e.
g.,
animal
and
vegetable
oils).
We
solicited
comments
on
the
appropriateness
of
this
approach.

Comments:
Support
for
proposal.
(82,
121,
168,
L8)
"Section
311
of
the
CWA
is
unusual,
in
that
it
is
the
only
section
of
the
Act
that
has
its
own
definition
section.
These
definitions
include
one
for
oil.
It
is
the
same
definition
as
the
one
presently
appearing
in
part
112.
There
is
nothing
in
section
311(
j)(
1)(
C)
that
indicates
that
Congress
contemplated
a
departure
from
this
oil
definition
for
prevention
regulations.
EPA
must
stick
with
the
present
definition
of
oil.
As
a
matter
of
fact,
a
vegetable
oil
spill
resulted
in
a
significant
duck
kill
on
the
upper
Mississippi
in
the
1960's."
(121)

Opposition
to
proposal.
Our
expanded
interpretation
of
what
constitutes
oil
will
subject
many
more
facilities
to
the
SPCC
Plan
preparation
requirements,
or
compel
many
facility
75
owners
or
operators
to
revise
existing
Plans.
It
is
too
broad.
(89,
155,
184,
189)
We
should
present
our
definition
for
public
comment.
(190)

Petroleum
products
only.
"The
inclusion
of
refined
petroleum
in
this
interpretation
includes
a
broad
category
of
materials
that
do
not
necessarily
fall
within
the
original
intent
of
Congress....
Releases
from
the
storage
of
many
of
these
chemicals
and
materials
are
currently
regulated
by
other
EPA
programs,
such
as
those
found
in
CERCLA
Section
304
and
SARA
Title
III."
(89)
"No
mention
is
made
in
the
Clean
Water
Act,
40
CFR
Part
110,
or
the
Deep
Water
Port
Act
to
vegetable
oil."
EPA
should
"(
L)
imit
the
definition
of
oil
to
petroleumbased
crude
oil
and
derivative
products
as
intended
by
the
Clean
Water
Act."
(110)

Other
Federal
and
State
rules.
"PG&
E
believes
that
this
definition
sweeps
too
broadly
and
is
inconsistent
with
parallel
federal
and
state
regulations
which
regulate
the
use,
containment,
and
discharge
of
oil
and
petroleum
products.
..
PG&
E
encourages
EPA
to
adopt
the
UST
definition
of
petroleum
as
it
applies
to
the
preparation
of
SPCC
plans."
(78,
111,
125,
184)

Specific
substances.
We
should
include
in
our
definition
of
oil,
examples
of
the
materials
covered
under
part
112.
(62,
103,
156)
Asks
that
we
explicitly
state
the
types
of
products
regulated
under
part
112
so
that
State
and
local
regulatory
agencies
do
not
make
arbitrary
and
capricious
interpretations.
(189)
"Clarification
of
the
definition
of
`oil'
is
recommended.
...
Considerable
confusion
on
the
definition
of
oil
still
exists."
(190,
L7)

Asphalt
cement.
We
should
clarify
whether
our
definition
includes
asphalt
cement
and
other
oil­
containing
products
that
are
not
liquid
at
ambient
temperature.
(76)

Viscosity.
"There
is
no
provision
or
consideration
of
the
potential
of
the
stored
material
to
spill
off­
site.
For
example,
`petroleum'
includes
lubricating
materials
and
asphalt
cement
which
are
highly
viscous
and
could
not
flow
very
far
if
a
tank
or
valve
is
damaged
or
vandalized.
The
potential
for
harm
to
any
person,
property
or
the
environment
is
extremely
limited."
(125,
149)

Chemicals
and
solvents.
We
should
change
the
definition
to
include
"chemicals
and
solvents
that
are
stored
in
bulk
in
tanks
in
a
manner
similar
to
oils
and
(that)
may
cause
comparable
water
pollution
problems
if
discharged
in
harmful
quantities
as
defined
under
40
CFR
Part
110."
(9)

Aromatic
hydrocarbons.
Asks
whether
"aromatic
hydrocarbons
and/
or
subsequent
derivatives"
are
considered
oil.
"Dow
does
not
believe
that
it
is
EPA's
intent
to
regulate
such
materials
under
40
CFR
Part
112."
(L7).
76
Gasoline
and
diesel
fuel.
"The
definition
of
oil
should
exclude
gasoline
and
diesel
fuel.
The
high
volatility
of
diesel
fuel
and
gasoline
results
in
rapid
evaporation
of
spilled
fuel,
thereby
reducing
the
pollution
potential
of
the
substance."
(128)

Hydrophobic
materials.
"Are
hydrophobic
materials
of
low
molecular
weight
and
high
vapor
pressure
exempt
­
they
would
not
impact
water
quality
(ie.
[sic]
tanks
of
propane)."
(62)

Mineral
oil.

Legislative
intent.
"The
Agency
should
limit
the
definition
of
`oil'
to
petroleum
and
petroleum
refinery
products
and
exclude
mineral
oils
and
oils
with
a
pour
point
above
60
degrees
Fahrenheit
from
that
definition."
(125)

Toxicity.
We
should
exclude
dielectric
fluids
from
part
112
because
they
are
used
operationally
in
electrical
equipment
and
have
"more
favorable
toxicity
characteristics"
than
most
petroleum
refinery
products.
(98,
125,
184)

Mixtures.

Bilge
water.
"In
short,
bilge
water
is
not
the
same
as
oil.
Accordingly,
your
regulation
should
expressly
exclude
bilge
water
from
the
same
stringent
requirements
as
are
imposed
upon
oil
spillage."
(45)

Brine
and
other
substances.
"The
definition
of
oil
does
not
refer
to
substances
mixed
with
oil.
A
clarification
must
be
made
as
to
whether
the
proposed
rules
are
intending
to
regulate
just
the
handling
of
oil
or
the
handling
of
oil
and
oil
mixed
with
any
other
substance
(e.
g.,
brine
tanks)"
(154)

Hazardous
substances.
"Are
other
hazardous
substances
potentially
regulated
by
this
statute
(are)
specifically
exempt
from
SPCC
requirements."
(162)

Volume,
less
than
10%
oil.
"GM
believes
the
definition
of
`oil'
should
be
amended
to
exclude
solutions
of
materials
containing
low
concentrations
of
oil,
e.
g.,
less
than
10%
by
volume.
Oil
solutions
of
low
concentration,
if
released,
do
not
pose
as
great
of
a
risk
to
the
environment,
as
compared
to
concentrated
oil
solutions
or
compounds."
(90)

Non­
petroleum
oils.
77
Include.
"The
definition
of
`oil'
should
specifically
include
non­
petroleum
oils,
such
as
animal
and
vegetable
oils.
These
oils
pose
many
of
the
same
hazards
in
a
spill
situation
as
do
the
petroleum
oils...."
(27,
123)

Exclude.
"...(
N)
on­
petroleum
based
oils
such
as
animal
and
vegetable
fats
and
soils
should
be
exempt
from
all
oil
40
CFR
112
requirements."
(56,
162)
"It
would
make
more
sense
to
exclude
animal/
vegetable
oils
and
include
petroleum
products
such
as
solvents
which
pose
a
much
greater
threat
to
the
environment...."
(L17,
L26)

Petroleum
and
its
derivatives.

Crude
oil.
We
should
define
crude
oil
in
part
112
"so
that
refined
products
such
as
diesel
fuel
and
gasoline
may
be
distinguished
from
unrefined
crude
oil."
We
should
define
crude
oil
as
"an
unrefined
mixture
of
naturally
occurring
hydrocarbons
produced
from
a
well
that
is
a
liquid
at
a
standard
temperature
of
60
degrees
Fahrenheit
and
14.73
psia."
(58)

Petrochemicals.

Exclude.
"For
example,
EPA
should
specify
(with
examples)
that
petrochemicals,
such
as
xylene,
are
not
included
in
the
definition
of
`oil'."
(103)

Include.
We
should
include
only
crude
oil
and
refined
petroleum
products
in
our
definition
of
oil.
(66)
Because
we
already
regulate
refined
petroleum
materials
under
other
EPA
programs
(e.
g.,
CERCLA
Section
304,
SARA
Title
III,
RCRA
Subtitles
C
and
D),
a
broad
definition
of
oil
"will
confuse
industries
about
regulatory
compliance
and
interdepartmental
Agency
responsibilities."
(89)
We
should
include
only
petroleum
and
"petroleum
refinery
products."
(125,
189)

Differentiate.
"The
term
`refined
petroleum
products'
...
needs
sharpening.
Not
only
are
substances
like
fuel
oil
or
diesel
fuel
or
lubricating
oils
`refined
petroleum
products,
'
but
so
are
other
substances
which
clearly
are
not
oil­
like
such
as
ethylene/
polyethelene,
propylene/
polypropylene,
styrene/
polystyrene
which
are
...
clearly
not
oil­
like."
(L26)

Solid
and
gaseous
oils.
"We
believe
that
those
`oils'
which
are
solids
at
ambient
temperatures
should
not
fall
within
the
scope
of
this
rulemaking.
Such
`oils'
will
not
pose
the
same
kind
of
water
pollution
`problem'
as
`true
oils'
and
should
be
addressed
separately."
(33,
101,
102,
113)

Synthetic
oils.
78
Exclude.
"As
synthetic
products,
such
liquids
do
not
`fit
EPA's
definition
of
`oil'
nor
are
they
specifically
addressed
under
the
CWA.
...
EPA
should,
instead,
specifically
exempt
`synthetic
oils
and
similar
oil­
like
liquids'
that
do
not
fit
its
`definition'
of
`oil'
...."
(33)
"Similarly,
mineral
oil
dielectric
fluids
should
be
excluded
because
they
too
have
low
toxicity
and
are
used
operationally,
even
though
they
are
petroleum
based."
(98,
125,
156)

Transformer
oil.
If
we
decide
to
change
the
current
definition,
we
should
add
transformer
oil
to
the
list
of
examples.
(168)

Used
and
waste
oil.
"The
definition
should
be
expanded
to
included
[sic]
used
oils
or
the
waste
forms
of
all
subject
materials."
(87)

Vegetable
oils,
animal
fats.
Differences
from
petroleum
oils.

Clarification
needed.
Asks
us
to
clarify
whether
vegetable
and
mineral
oils
are
covered
under
part
112.
(139)

Exclude
from
rule.
"ACMS
believes
that
edible
oils
should
not
be
governed
by
the
OPA
rulemaking."
"The
EPA
should
consider
not
applying
these
rules
to
the
handling
and
storage
of
animal
fats
and
oils,
particularly
those
which
are
miscible
in
water."
(51,
56,
137,
143)

Differences.
"The
physical
characteristics
of
vegetable
oils
such
as
corn
oil
are
so
markedly
different
that
reliance
on
a
narrow
technical
reading
of
the
term
`oil'
is
not
credible."
(37,
114,
137,
156,
175)
"Edible
oils
do
not
create
a
hydrocarbon
`sheen'
on
water
surfaces
as
do
petroleum
oils.
...
Edible
oils
are
very
biodegradable
and
present
a
negligible
environmental
threat
to
aquatic
and
animal
life
unless
spilled
in
very
large
amounts
in
under
unique
circumstances.
...
One
option
EPA
should
consider
is
providing
needed
flexibility
in
the
SPCC
rules
would
be
to
apply
them
as
guidelines
where
specifically
applicable
to
the
edible
oils
industry."
(137,
157)
"The
Department
believes
that
EPA
should
consider
developing
regulations
that
respond
to
the
types
of
oil
that
may
be
included
within
a
facility."
(175)

Legislative
intent.
"...
BHP
believes
that
the
Agency
is
making
an
unreasonable
extension
of
the
definition
of
oil
to
include
such
substances."
(42,
56)

Risk.
"Unlike
petroleum
products,
vegetable
oils:
are
rapidly
and
completely
biodegradable;
pose
no
risk
to
human
health
if
spilled
in
drinking
water
sources;
are
not
flammable;
are
easily
handled
by
POTWs.
The
only
detrimental
environmental
impact
from
a
major
spill
of
vegetable
oil
would
be
temporary
oxygen
depletion
in
surface
waters
and
its
attendant
effect
on
fish."
(56,
137,
157).
79
State
law
(California).
"We
do
not
consider
animal
and
vegetable
oils
to
be
subject
to
our
oil
pollution
statutes.
This
difference
is
not
fatal
to
our
regulatory
process
as
long
as
the
states
continue
to
have
the
flexibility
of
planning
and
regulating
in
this
area
without
preemption."
(193)

Risk
to
the
environment.
Our
failure
to
distinguish
between
oils
based
on
potential
to
cause
harm
to
the
environment
subjects
owners
or
operators
to
unwarranted
costs.
(184)
We
should
recognize
that
for
different
types
of
oils,
the
quantity
necessary
to
cause
irreversible
environmental
damage
is
different.
(L2)

Response:
Support
for
proposal.
We
appreciate
the
commenters'
support.
We
disagree
that
the
definition
of
oil
will
subject
additional
facilities
to
SPCC
requirements,
and
currently
covered
facilities
to
additional
requirements.
The
definition
does
not
expand
what
is
oil,
it
merely
clarifies
which
substances
are
included.

Authority.
We
disagree
that
our
authority
only
extends
to
petroleum­
based
oils.
Our
interpretation
is
consistent
with
Congressional
intent
as
expressed
in
section
311(
a)(
1)
of
the
CWA,
which
extends
to
all
types
of
oils
in
any
form.
EPA's
definition
tracks
that
statutory
definition.
Our
revised
definition
also
reflects
EORRA
requirements
for
differentiation.
EORRA
did
not
expand
or
contract
the
universe
of
substances
that
are
oils,
it
only
required
differentiation,
when
necessary,
between
the
requirements
for
facilities
storing
or
using
different
types
of
oil.

What
is
oil.
EPA
interprets
the
definition
of
oil
to
include
all
types
of
oil,
in
whatever
form,
solid
or
liquid.
That
includes
synthetic
oils,
mineral
oils,
vegetable
oils,
animal
fats,
petroleum
derivatives,
oil
refuse,
oil
mixed
with
wastes
other
than
dredged
spoil,
etc.
We
do
not
regulate
products
similar
to
oil
(for
examples,
non­
oil
chemicals),
but
only
oil
under
part
112.
A
definition
based
on
liquidity
would
exclude
solid
oils,
such
as
certain
animal
fats,
a
result
that
would
be
inconsistent
with
Congressional
intent.
Concerning
gaseous
oils,
see
our
discussion
on
Highly
volatile
liquids
in
the
preamble
to
today's
rule.

Specific
substances.

Aromatic
hydrocarbons.
Aromatic
hydrocarbons
may
or
may
not
be
oil,
depending
on
their
physical
characteristics
and
environmental
effects.
Some
aromatic
hydrocarbons
are
hazardous
substances.

Asphalt
cement.
As
to
certain
specific
substances,
asphaltic
cement
is
oil
because
it
is
a
petroleum­
based
product
and
exhibits
oil­
like
characteristics.
A
discharge
of
asphaltic
cement
may
violate
applicable
water
quality
standards,
or
cause
a
film
or
sheen
or
discoloration
of
the
water
or
adjoining
shorelines
or
cause
a
sludge
or
emulsion
to
be
deposited
beneath
the
surface
of
the
water
or
upon
adjoining
shorelines.
80
Bilge
water.
Bilge
water
that
contains
sufficient
oil
such
that
its
discharge
would
violate
the
standards
set
out
in
40
CFR
110.3
is
considered
oil.
The
percentage
of
oil
concentration
in
the
water
is
not
determinative
for
the
purpose
of
the
definition
or
the
discharge
standards.

Crude
oil.
We
did
not
propose
a
definition
of
the
term
crude
oil
in
part
112,
nor
do
we
use
it,
except
as
an
example
of
a
discharge
that
may
occur
at
an
onshore
drilling
and
workover
facility
(see
§112.
10(
c)).
Therefore,
we
cannot
finalize
such
a
definition.

Highly
volatile
liquids.
We
do
not
consider
highly
volatile
liquids
that
volatilize
on
contact
with
air
or
water,
such
as
liquid
natural
gas,
or
liquid
petroleum
gas,
to
be
oil.
Such
substances
do
not
violate
applicable
water
quality
standards,
do
not
cause
a
reportable
film
or
sheen
or
discoloration
upon
the
surface
of
water
or
adjoining
shorelines,
do
not
cause
a
sludge
or
emulsion
to
be
deposited
beneath
the
surface
of
the
water
or
upon
adjoining
shorelines,
and
are
not
removable.
Therefore,
there
would
be
no
reportable
discharge
as
described
in
40
CFR
110.3.

Mixtures.
Oil
means
oil
of
any
kind
or
in
any
form,
including,
but
not
limited
to:
fats,
oils,
or
greases
of
animal,
fish,
or
marine
mammal
origin;
vegetable
oils,
including
oils
from
seeds,
nuts,
fruits,
or
kernels;
and,
other
oils
and
greases,
including
petroleum,
fuel
oil,
sludge,
synthetic
oils,
mineral
oils,
oil
refuse,
or
oil
mixed
with
wastes
other
than
dredged
spoil.

Other
Federal
and
State
rules.
While
our
definition
may
differ
from
other
Federal
rules,
it
is
necessary
to
implement
the
purposes
of
the
CWA.

RCRA.
Although
releases
or
discharges
of
some
refined
petroleum
products
may
be
regulated
under
the
Solid
Waste
Disposal
Act
as
waste
products,
that
program
is
dedicated
more
to
waste
management,
and
does
not
regulate
storage
of
nonwaste
oil.
The
definition
of
petroleum
in
40
CFR
part
280
is
a
subset
of
the
part
112
definition
of
"oil."
The
part
112
definition
of
oil
is
broader
than
the
part
280
definition
of
petroleum
because
part
112
regulates
all
types
of
oils,
whereas
part
280
regulates
only
petroleum.

State
rules.
While
States
may
choose
to
regulate
all
oils
or
some
oils,
the
CWA
definition
is
designed
to
prevent
the
discharge
of
all
oils.

Public
comment.
In
response
to
the
recommendation
that
we
present
our
definition
for
public
comment,
we
agree.
We
did
so
in
1991
by
publishing
the
proposed
rule
in
the
Federal
Register.

Risk
to
the
environment.
We
disagree
that
in
the
definition
of
oil
we
should
distinguish
between
oils
by
degree
of
risk
or
percentage
of
oil
concentration.
The
risk
or
percentage
of
oil
concentration
does
not
change
the
fact
that
the
substance
is
still
oil
and
may
harm
the
environment
if
discharged
into
it.
We
likewise
disagree
that
we
81
should
distinguish
between
oils
by
degree
of
risk
for
definitional
purposes.
The
risk
does
not
change
the
fact
that
the
substance
is
still
oil
and
may
harm
the
environment
if
discharged
into
it.
Finally,
we
disagree
that
we
should
exclude
from
the
definition
oil
based
on
pour
point,
propensity
to
migrate
off­
site,
or
viscosity
factors.
Any
oil
discharged
to
the
environment
may
cause
harm
that
the
rule
is
designed
to
prevent.

All
oils,
including
animal
fats
and
vegetable
oils,
can
harm
the
environment
in
many
ways.
Oil
can
coat
the
feathers
of
birds,
the
fur
of
mammals
and
cause
drowning
and
hypothermia
and
increased
vulnerability
to
starvation
and
predators
from
lack
of
mobility.

Oils
can
act
on
the
epithelial
tissue
of
fish,
accumulate
on
gills,
and
prevent
respiration.
The
oil
coating
of
surface
waters
can
interfere
with
natural
processes,
oxygen
diffusion/
reaeration
and
photosynthesis.
Organisms
and
algae
coated
with
oil
may
settle
to
the
bottom
with
suspended
solids
along
with
other
oily
substances
that
can
destroy
benthic
organisms
and
interfere
with
spawning
areas.

Oils
can
increase
biological
or
chemical
oxygen
demand
and
deplete
the
water
of
oxygen
sufficiently
to
kill
fish
and
other
aquatic
organisms.

Oils
can
cause
starvation
of
fish
and
wildlife
by
coating
food
and
depleting
the
food
supply.
Animals
that
ingest
large
amounts
of
oil
through
contaminated
food
or
preening
themselves
may
die
as
a
result
of
the
ingested
oil.
Animals
can
also
starve
because
of
increased
energy
demands
needed
to
maintain
body
temperature
when
they
are
coated
with
oil.

Oils
can
exert
a
direct
toxic
action
on
fish,
wildlife,
or
their
food
supply.
Oils
can
taint
the
flavor
of
fish
for
human
consumption
and
cause
intestinal
lesions
in
fish
from
laxative
properties.
Tainted
flavor
of
fish
for
human
consumption
may
indicate
a
disease
in
the
fish
which
could
render
them
inedible
and
thus
have
a
substantial
impact
on
the
fishermen
who
harvest
them
and
communities
who
may
rely
on
them
for
a
food
supply.

Oils
can
foul
shorelines
and
beaches.
Oil
discharges
can
create
rancid
odors.
Rancid
odors
may
cause
both
health
impacts
and
environmental
impacts.
For
example,
the
1991
Wisconsin
Butter
Fire
and
Spill
resulted
in
a
discharge
of
melted
butter
and
lard.
After
the
cleanup
was
largely
completed,
the
Wisconsin
Department
of
Natural
Resources
declared
as
hazardous
substances
the
thousands
of
gallons
of
melted
butter
that
ran
offsite
and
the
mountain
of
damaged
and
charred
meat
products
spoiling
in
the
hot
sun
and
creating
objectionable
odors.
The
Wisconsin
DNR
stated
that
these
products
posed
an
imminent
threat
to
human
health
and
the
environment.
62
FR
54526.

Our
revised
definition
also
reflects
EORRA
requirements
for
differentiation.
EORRA
did
not
expand
or
contract
the
universe
of
substances
that
are
oils,
it
only
required
differentiation,
when
necessary,
between
the
requirements
for
facilities
storing
or
using
82
different
types
of
oil.
Because
at
the
present
time
EPA
has
not
proposed
differentiated
SPCC
requirements
for
public
notice
and
comment,
the
requirements
for
facilities
storing
or
using
all
classes
of
oil
will
remain
the
same.
However,
we
have
published
an
advance
notice
of
proposed
rulemaking
seeking
comments
on
how
we
might
differentiate
among
the
requirements
for
the
facilities
storing
or
using
various
classes
of
oil.
64
FR
17227,
April
8,
1999.
If
after
considering
these
comments,
there
is
adequate
justification
for
differentiation
among
the
requirements
for
those
facilities,
we
will
propose
rule
changes.

V
­10Partially
buried
tank
Background:
In
1991,
we
proposed
to
define
a
partially
buried
tank
to
clarify
the
distinction
between
such
a
tank
and
a
UST.
We
proposed
to
define
a
partially
buried
tank
as
a
storage
tank
that
is
partially
inserted
or
constructed
in
the
ground,
but
not
fully
covered
with
earth.
We
have
renamed
underground
tanks
in
this
rule
as
"completely
buried
tanks,"
i.
e.,
those
tanks
completely
covered
with
earth.
A
partially
buried
tank
is
an
aboveground
container
for
purposes
of
the
part
112.

Comments:
The
definition
as
proposed
is
"undecipherable"
and
should
be
rewritten.
Suggests
another
definition
for
clarity.
(121)
We
should
adopt
the
part
280
UST
definition
for
partially
buried
tank,
which
includes
any
tank
system
such
as
tank
and
piping
which
has
a
volume
of
10
percent
or
more
beneath
the
surface
of
the
ground.
(90,
180)
Asks
whether
partially
buried
tanks
will
be
subject
to
both
parts
112
and
280,
and
if
not,
whether
part
112
provides
adequate
regulation
of
leaks
to
the
ground.
(L17)

Response:
We
agree
that
the
definition
could
be
clearer
and
have
clarified
it.
We
decline
to
adopt
the
part
280
UST
definition
(at
40
CFR
280.12)
and
to
classify
partially
buried
tanks
as
completely
buried
tanks,
because
they
are
not.
The
UST
definition
might
also
exclude
some
tanks
or
containers
which
would
be
covered
by
the
SPCC
definition.
The
UST
definition
includes
tanks
whose
volume
(including
the
volume
of
underground
pipes
connected
thereto)
are
10
percent
or
more
beneath
the
surface
of
the
ground.
The
SPCC
definition
of
"partially
buried
tank"
contains
no
volume
percentage
and
applies
to
any
tank
that
is
partially
inserted
or
constructed
in
the
ground,
but
not
entirely
below
grade,
and
not
completely
covered
with
earth.
Therefore,
some
partially
buried
tanks
will
continue
to
be
subject
to
both
parts
112
and
280.

We
clarify
that
partially
buried
tanks
may
be
covered
not
only
with
earth,
but
with
sand,
gravel,
asphalt,
or
other
material.
The
clarification
brings
the
definition
into
accord
with
the
coverings
noted
in
the
definition
of
"bunkered
tank."
We
added
a
sentence
to
the
definition
noting
that
partially
buried
tanks
are
considered
aboveground
storage
containers
for
purposes
of
this
part.

V
­11Permanently
closed
(See
also
section
IV.
C
of
this
document)

Background:
In
1991,
in
§112.2(
o),
we
proposed
to
define
the
term
permanently
closed
to
clarify
whether
facilities
and
tanks
are
excluded
from
part
112.
In
83
§112.2(
o)(
1),
we
proposed
to
define
permanently
closed
as
a
tank
and
its
connecting
lines
or
a
facility
from
which
an
owner
or
operator
has
removed
all
liquid
and
sludge,
disposing
of
removed
waste
products
in
accordance
with
all
applicable
State
and
Federal
requirements.
Proposed
§112.2(
o)(
2)
would
have
provided
that
to
call
a
tank
or
facility
permanently
closed,
an
owner
or
operator
must
have
tested
the
tank
for
and
rendered
the
tank
free
from
explosive
vapor,
using
a
combustible
gas
indicator,
explosimeter,
or
other
type
of
atmospheric
monitoring
instrument
to
determine
the
lower
explosive
limit
(LEL).
The
proposed
definition
further
would
have
provided
that
tank
vapors
must
remain
below
the
LEL,
as
defined
by
EPA
and
the
Occupational
Safety
and
Health
Administration
(OSHA).
Proposed
§112.2(
o)(
3)
would
require
blanking
off
all
connecting
lines,
closing
and
locking
valves,
and
posting
signs
warning
that
the
tank
is
permanently
closed
and
that
there
are
no
vapors
above
the
lower
explosive
limit.

Comments:
Support
for
definition.
"The
inclusion
of
a
definition
of
a
`permanently
closed
tank'
is
helpful."
(27).

Opposition
to
definition.
"It
is
recommended
that
the
concept
of
`permanently
closed'
tanks
be
removed
from
the
SPCC
regulations.
If
a
tank
is
not
used
for
the
storage
of
oil,
it
is
simply
not
subject
to
the
provisions
of
the
SPCC
regulations."
(42,
67,
85,
86,
110,
125,
175)
We
should
include
in
the
term
permanently
closed
those
tanks
without
oil
and
with
all
connections
severed.
(101,
125,
165,
170,
L2,
L15)
If
our
primary
goal
is
to
protect
navigable
waters,
our
definition
of
permanently
closed
is
too
stringent.
(75,
86,
125,
155,
167,
170)

Other
substances.
Our
definition
should
include
tanks
that
have
been
permanently
closed
and
then
loaded
with
liquid
other
than
oil.
(51)

Regulatory
criteria.
"It
is
important
that
the
Agency
separate
permanently
closed
tanks
from
regulated
tanks
and
make
the
criteria
easy
to
observe
during
SPCC
inspections."
(168,
190)

Connecting
lines.
Support
the
proposed
provision
in
the
permanently
closed
definition
to
blank
off
all
connecting
lines.
However,
we
should
require
that
owners
or
operators
blank
off
all
connecting
lines
at
both
ends.
(27,
L12)
We
are
overreaching
our
authority
by
requiring
lines
to
be
blanked
off.
(58)
Asks
that
we
clarify
the
term
connecting
lines.
Assumes
that
we
mean
the
sections
of
pipe
that
run
between
the
tank
and
the
nearest
block
valve.
(67,
96,
102)

Cost.
It
would
be
expensive
to
eventually
close
tanks
currently
in
operation
because
owners
or
operators
will
have
to
pay
for
explosivity
detection
services,
determination
of
LEL,
placarding
tanks,
and
waste
disposal.
(28,
31,
165)

Decommissioned
tanks.
"The
definition
should
include
tanks
which
have
been
decommissioned
in
this
manner.
...
If
the
decommissioning
procedure
follows
that
prescribed
by
the
procedure
in
the
currently­
proposed
`permanently
closed'
definition,
a
decommissioned
tank
no
longer
poses
a
threat
of
oil
pollution."
(L12)
84
Explosive
vapors.
"...
(P)
rovisions
relating
to
combustible
vapors
or
dust
clearly
fall
outside
the
scope
of
the
Clean
Water
Act."
(42,
58,
67,
71,
75,
95,
102,
110,
125,
155,
167,
170,
175,
L12)
EPA
should
eliminate
the
25%
LEL
because
it
is
"NOT
universally
acceptable
to
OSHA."
(33)
Rather
than
render
each
tank
free
of
explosive
vapor,
owners
or
operators
should
maintain
tanks
below
the
LEL
for
the
tank's
material.
(33)
Vapor
testing
for
small
tanks
is
excessive
and
should
be
necessary
only
for
a
tank
with
a
capacity
greater
than
42,000
gallons
or
1,000
barrels.
(113)
It
would
be
difficult
or
impossible
to
remove
all
vapors,
and
we
should
delete
this
element
from
the
permanently
closed
definition.
(L2)
Detection
services
would
be
too
expensive.
(L15)

Signs.
The
proposed
requirement
to
post
a
sign
on
permanently
closed
tanks
is
beyond
the
scope
of
our
CWA
authority.
(58)
"Additionally,
the
placement
of
a
sign
on
a
tank
indicating
that
it
has
been
gas
freed
is
not
a
good
safety
practice.
This
could
lead
an
inexperienced
worker
to
believe
that
confined
space
entry
without
additional
testing
of
the
atmosphere
within
the
tank
is
acceptable.
This
cold
also
apply
to
someone
initiating
hot
work,
such
as
welding
or
cutting,
on
the
tank.
If
gases
were
to
build
up
within
the
tank
after
the
initial
gas
freeing
procedure
for
some
unexpected
reason,
a
sign,
such
as
that
proposed,
could
have
catastrophic
results
while
providing
no
benefit."
(67,
86,
102,
110,
175,
L2)

Retroactive
enforcement.
"The
definition
of
`permanently
closed'
should
not
be
applied
retroactively
to
tanks
that
have
been
abandoned
prior
to
adoption
of
this
definition."
Such
tanks,
in
most
instances,
have
been
abandoned
and
empty
for
many
years
and
pose
no
threat
of
an
oil
spill.
It
would
be
a
severe
economic
burden
to
require
that
operators
perform
the
proposed
procedures
on
such
a
wide
universe
of
tanks."
The
commenters
did
not
provide
specific
cost
estimates.
(28,
31,
37,
101,
113,
165,
L15)

Scope
of
rule.
The
provisions
to
regulate
permanently
closed
tanks
are
unclear.
Asks
whether
we
proposed
to
exclude
permanently
closed
tanks
from
all
of
40
CFR
part
112.
(84)
Part
112
technical
requirements
should
not
apply
to
permanently
closed
tanks.
(102)

Temporarily
closed
tanks.
Suggests
"temporarily
closed"
definition."
Temporary
tanks
should
be
excluded
from
the
definition
"provided
the
operator
can
show
that
the
tanks
have
been
shut­
in
and
all
fluid
removed
down
to
the
pipeline
connection."
(71,
L2,
L12)

Waste
disposal.

Authority.
"USEPA
does
appear
to
be
within
its
statutory
authority
to
require
removal
of
all
liquid
and
sludge
from
a
permanently
closed
tank
since,
conceivably,
such
liquid
or
sludge,
if
released,
could
cause
a
discharge
of
oil
in
harmful
quantities
into
a
navigable
water."
(58)

Opposition
to
proposal.
85
Other
programs.
"Waste
disposal
is
covered
under
other
programs
and
should
not
be
a
consideration
for
spill
prevention
unless
flowable
oil
is
part
of
the
waste."
(28,
31,
42,
101,
110,
165,
167,
L15)

Unnecessary.
The
definition
is
a
"surreptitious
means
of
inserting
regulations
with
the
definition
section
of
40
CFR
part
112.
...
(D)
isposition
of
tank
contents
has
nothing
to
do
with
the
definition
of
a
tank."
(110)

Sludge
removal.
"A
small
amount
of
sludge
left
on
the
bottom
of
the
tank
should
not
prevent
it
from
being
classified
as
empty."
(75)
"`
Permanently
closed'
should
not
require
the
total
removal
of
sludge
unless
the
sludge
is
free
flowing,
provided
that
the
provision
for
meeting
explosive
vapors
can
be
met.
It
has
been
our
experience
that
it
can
be
very
difficult
to
remove
old
sludge
from
#6
fuel
oil
tanks.
It
appears
that
the
only
way
of
removing
the
sludge
is
to
dismantle
the
tank."
(161)

Response:
Support
for
proposal.
We
appreciate
commenter
support.
A
definition
is
necessary
to
clarify
when
a
container
is
permanently
closed
and
no
longer
used
for
the
storage
of
oil.
Containers
that
are
only
closed
temporarily
may
be
returned
to
storage
purposes
and
thus
may
present
a
threat
of
discharge.
Therefore,
they
will
continue
to
be
subject
to
the
rule.

Connecting
lines.
We
agree
with
the
commenter's
assumed
definition
of
connecting
lines.
Connecting
lines
that
have
been
emptied
of
oil,
and
have
been
disconnected
and
blanked
off,
are
considered
permanently
closed.

Cost.
We
have
deleted
the
proposed
requirements
to
render
the
container
free
of
explosive
vapor
by
testing
to
determine
the
LEL.
We
have
also
deleted
all
references
to
waste
disposal.
The
sign
noting
that
a
container
is
permanently
closed
(with
date
of
closure)
should
be
relatively
inexpensive.

Decommissioned
tanks.
If
"decommissioning"
refers
to
the
criteria
for
permanent
closing
of
a
container,
then
there
is
no
need
to
include
such
terminology
in
the
definition
because
permanent
closure
will
include
such
tanks.
Otherwise,
the
containers
are
not
permanently
closed
and
should
not
be
included.

Explosive
vapors.
We
deleted
proposed
§112.2(
o)(
2)
on
the
suggestion
of
commenters
that
references
to
explosive
vapors
are
an
OSHA
matter
and
inappropriate
for
EPA
rules.
We
modified
proposed
§112.2(
o)(
3)
to
eliminate
the
reference
to
signs
warning
that
"vapors
above
the
LEL
are
not
present,"
because
the
operator
cannot
guarantee
that
warning
remains
correct.
To
help
prevent
a
buildup
of
explosive
vapors,
we
have
revised
the
definition
to
provide
that
ventilation
valves
need
not
be
closed.
We
agree
with
commenters
that
a
sign
might
be
misleading
and
dangerous.
86
Non­
oil
products.
Containers
that
store
products
other
than
oil
and
never
store
oil,
are
not
subject
to
the
SPCC
rule
whether
they
are
"permanently
closed"
as
defined
or
not.
If
the
containers
sometimes
store
oil
and
sometimes
store
non­
oil
products,
they
are
subject
to
the
rule.

Retroactive
enforcement.
We
believe
that
containers
that
have
been
permanently
closed
according
to
the
standards
prescribed
in
the
rule
qualify
for
the
designation
of
"permanently
closed,"
whether
they
have
been
closed
before
or
after
the
effective
date
of
the
rule.
Containers
that
cannot
meet
the
standards
prescribed
in
the
rule
will
not
qualify
as
permanently
closed.
We
disagree
that
the
cost
of
such
closure
is
prohibitive.
We
have
simplified
the
proposal
by
deleting
the
proposed
requirement
to
render
the
tank
free
of
explosive
vapor.
Therefore,
costs
are
lower.
To
clarify
when
a
container
has
been
closed,
we
have
amended
the
rule
to
require
that
the
sign
noting
closure
show
the
date
of
such
closure.
The
date
of
such
closure
must
be
noted
whether
it
occurred
before
or
after
the
effective
date
of
this
provision.
Some
States
and
localities
require
a
permit
for
tank
closure.
A
document
noting
a
State
closure
inspection
may
serve
as
evidence
of
container
closure
if
it
is
dated.

Scope
of
rule.
The
exemption
for
a
permanently
closed
container
or
facility
applies
to
all
of
part
112.

Waste
disposal.
Reference
to
waste
disposal
in
accordance
with
Federal
and
State
rules
in
proposed
§112.2(
o)
was
deleted
as
unnecessary
surplus.
EPA
agrees
that
other
programs
adequately
handle
waste
disposal.

V
­12
Person
Background:
In
the
1991
proposal,
we
proposed
to
include
a
definition
of
person
that
was
substantively
unchanged
from
the
current
rule.

Comments:
"EPA
should
either
modify
its
regulatory
definition
of
person,
or
make
clear
that
the
United
States
is
bound
by
every
provision
of
these
regulations
for
any
failure
to
comply."
(35)

Response:
See
the
discussion
under
§112.1(
c)
for
the
applicability
of
the
rule
to
Federal
agencies
and
facilities.

V
­13
Production
facility
Background:
The
definition
of
"production
facility"
replaces
two
definitions
in
the
proposed
rule,
i.
e.,
Oil
drilling,
production,
or
workover
facilities
(offshore),
proposed
§112.2(
j),
and
Oil
production
facilities
(onshore),
proposed
§112.2(
k).
We
replaced
the
two
proposed
definitions
with
the
revised
definition
for
editorial
brevity
as
the
proposed
definitions
contained
many
identical
elements.
This
editorial
effort
effects
no
substantive
changes
in
the
requirements
for
the
particular
types
of
production
facilities.
87
Each
facility
must
follow
the
requirements
applicable
to
that
facility,
which
is
generally
based
on
its
operations,
for
example,
a
workover
facility.

Comments:
Editorial
change.
"The
proposed
regulations
contain
new
definitions
for
oil
production
facilities
(onshore)
and
oil
production
facilities
(offshore).
These
definitions
should
be
replaced
by
a
single
definition
of
`production
facility'
that
is
identical
to
that
found
in
49
CFR
§195.2.
...
EPA
should
not
develop
new
definitions
for
terms
already
defined
in
existing
regulations
that
would
result
in
wide
spread
confusion
among
the
regulated
community."
(95,
102)
We
should
include
a
definition
for
onshore
drilling
and
workover
facilities.
The
proposed
definitions
of
the
terms
oil
production
facility
(onshore)
and
oil
production
facility
(offshore)
are
ambiguous,
because
of
inclusion
of
the
phrase,
"may
include."
(154)

Flowlines,
gathering
lines,
wells
and
separators.
"Oil
production
facilities
should
not
include
wells,
flow
lines,
gathering
lines
or
separators."
(101,
165)
"These
pipelines
(gathering
lines)
have
never
been
subject
to
such
(SPCC)
requirements.
They
are
truly
transportation
lines
subject
to
Department
of
Transportation
regulations."
(71)
"The
term
should
also
exclude
oil
gathering
lines
since
it
is
virtually
impossible
to
comply
with
certain
provisions
of
the
regulation
without
excessive
and
unrealistic
expense.
How,
for
example
would
an
operator
provide
the
necessary
containment
for
his
gathering
lines
pursuant
to
section
112.7(
c)?"
(113)

Natural
gas
processing
operations.

Applicability
of
rules.
"IPAA
recommends
clarification
of
the
definition
of
`oil
production
facilities'
at
40
C.
F.
R.
§112.
2
to
ensure
that
natural
gas
processing
operations
are
treated
as
oil
production
facilities
under
the
rules.
That
clarification
should
ensure
the
appropriate
level
of
regulation
for
those
related
facilities
and
avoid
inadvertent
application
of
requirements
designed
for
larger
refining
and
marketing
facilities
to
natural
gas
processing."
(31,
86,
L12)

Risk.
"After
20
years
of
SPCC
regulation
of
E&
P
operated
natural
gas
processing
facilities,
there
is
no
evidence
that
demonstrates
that
these
facilities
have
a
different
or
higher
risk
of
causing
oil
spill
pollution
of
navigable
waters.
Therefore,
the
oil
pollution
requirements
should
not
be
different
than
those
for
other
E&
P
facilities."
(L12)

Single
geographical
oil
or
gas
field,
single
operator.
"The
inclusion
of
the
phrases
`in
a
single
geographical
oil
or
gas
field'
and
`operated
by
a
single
operator'
in
this
definition
is
confounding.
The
producing
segment
of
the
industry
in
some
cases
needs
to
be
able
to
combine
facilities
into
one
SPCC
plan
with
an
identification
of
the
wells
to
which
that
plan
applies.
We
question
whether
the
inclusion
of
the
word
`single'
would
preclude
an
operator's
ability
to
do
so."
(167)

Response:
Editorial
change.
DOT
definition.
We
changed
the
proposed
definition
to
be
more
consistent
with
the
DOT
definition,
found
at
49
CFR
195.2,
in
response
to
a
88
commenter
who
urged
consistency
in
EPA
and
DOT
definitions.
We
added
the
uses
of
the
piping
and
equipment
detailed
in
the
DOT
rule
to
our
proposal,
for
example,
"production,
extraction,
recovery,
lifting,
stabilization,
separation,
or
treating"
of
oil.
The
terms
"separation
equipment,"
used
in
the
proposed
definition
of
"oil
production
facilities
(onshore)",
and
"workover
equipment,"
used
in
the
proposed
definition
of
"oil
drilling,
production,
or
workover
facilities
(offshore)",
were
combined
into
a
generic
"equipment."
However,
we
also
modified
the
proposed
definition
to
reflect
EPA
jurisdiction.
We
added
the
word
"structure,"
which
was
not
in
the
DOT
definition,
to
cover
necessary
parts
of
a
production
facility.
We
also
added
examples
of
types
of
piping,
structures,
and
equipment.
These
examples
are
not
an
exclusive
list
of
the
possible
piping,
structures,
or
equipment
covered
under
the
definition.
The
new
definition
encompasses
all
those
facilities
that
would
have
been
covered
under
both
former
proposed
definitions.
As
we
proposed
in
1991,
and
as
in
the
current
rule,
we
have
retained
geographic
and
ownership
limitations.

Editorial
change.
We
have
eliminated
the
potential
ambiguity
caused
by
the
words
may
include
by
substituting
the
word
means.

Flowlines,
gathering
lines,
wells
and
separators.
EPA
disagrees
that
flowlines
and
gathering
lines,
as
well
as
wells
and
separators,
should
be
excluded
from
the
definition.
These
structures
or
equipment
are
integral
parts
of
production
facilities
and
should
therefore
be
included
in
the
definition.
We
also
disagree
with
the
argument
that
because
the
installation
of
structures
and
equipment
to
prevent
discharges
around
gathering
lines
and
flowlines
may
not
be
practicable,
EPA
will
be
flooded
with
contingency
plans.
First
of
all,
secondary
containment
may
be
practicable.
In
§112.7(
c),
we
list
sorbent
materials,
drainage
systems,
and
other
equipment
as
possible
forms
of
secondary
containment
systems.
We
realize
that
in
many
cases,
secondary
containment
may
not
be
practicable.
If
secondary
containment
is
not
practicable,
you
must
provide
a
contingency
plan
in
your
SPCC
Plan
following
the
provisions
of
part
109,
and
otherwise
comply
with
§112.7(
d).
We
have
deleted
the
proposed
1993
provision
that
would
have
required
you
to
provide
contingency
plans
as
a
matter
of
course
to
the
Regional
Administrator.
Therefore,
you
will
rarely
have
to
submit
a
contingency
plan
to
EPA.
The
contingency
plan
you
do
provide
in
your
SPCC
Plan
when
secondary
containment
is
not
practicable
for
flowlines
and
gathering
lines
should
rely
on
strong
maintenance,
corrosion
protection,
testing,
recordkeeping
and
inspection
procedures
to
prevent
and
quickly
detect
discharges
from
such
lines.
It
should
also
provide
for
the
quick
availability
of
response
equipment.

Natural
gas
processing
operations.
Because
natural
gas
is
not
oil,
natural
gas
facilities
that
do
not
store
or
use
oil
are
not
covered
by
this
rule.
However,
you
should
note,
that
drip
or
condensate
from
natural
gas
production
is
an
oil.
The
storage
of
such
drip
or
condensate
must
be
included
in
the
calculation
of
oil
stored
or
used
at
the
facility.

Single
geographical
oil
or
gas
field,
single
operator.
89
Single
geographical
oil
or
gas
field.
The
phrase
"a
single
geographical
oil
or
gas
field,"
may
consist
of
one
or
more
natural
formations
containing
oil.
The
determination
of
its
boundaries
is
area­
specific.
Such
formation
may
underlie
one
or
many
facilities,
regardless
of
whether
any
natural
or
man­
made
physical
geographical
barriers
on
the
surface
intervene
such
as
a
mountain
range,
river,
or
a
road.

Single
operator.
We
disagree
that
the
term
"a
single
operator"
is
confusing.
An
"owner"
or
"operator"
is
defined
in
§112.2
as
any
"person
owning
or
operating
an
onshore
facility
or
an
offshore
facility,
and
in
the
case
of
any
abandoned
offshore
facility,
the
person
who
owned
or
operated
or
maintained
such
facility
immediately
prior
to
abandonment."
A
"person"
is
not
restricted
to
a
single
natural
person.
"Person"
is
a
defined
term
in
the
rule
(at
§112.2)
which
includes
an
individual,
firm,
corporation,
association,
or
partnership.

V
­14
SPCC
Plan
or
Plan
(see
also
section
X.
A)

Background:
In
1991,
we
proposed
to
define
an
SPCC
Plan
or
Plan
to
further
explain
its
purpose
and
scope.

Comments:
Compliance.
"An
SPCC
plan
should
not
be
a
chronicle
of
actions
taken
to
comply
with
the
regulations.
Rather,
an
SPCC
plan
should
contain
information
which
is
necessary
to
prevent,
control,
or
take
countermeasures
in
response
to
a
discharge
of
oil.
Maintenance
of
records
to
demonstrate
compliance
is
addressed
in
other
sections."
(42)

Prevention
v.
Response.
"Change
the
definition
of
`SPCC
Plan'
to
"Spill
Prevention
and
Response
Plan'
means
a
plan
consisting
of
two
separate
entities:
a
Spill
Prevention
Plan
(SPP
or
`plan'),
described
in
sections
112.3
through
112.11
of
this
part,
and
a
Spill
Response
Plan
described
in
sections
to
be
added."
(121)

Response:
Compliance.
We
agree
that
the
Plan
does
not
document
compliance,
but
merely
spill
prevention
measures,
and
have
deleted
the
sentence
noting
that
the
Plan
documents
compliance
with
the
rule.
Compliance
is
determined
by
comparing
the
contents
of
the
Plan
with
the
regulations.

Prevention
v.
Response.
In
1997,
we
proposed
a
new
definition
of
an
Spill
Prevention,
Control,
and
Countermeasure
Plan,
SPCC
Plan,
or
Plan;
and
withdrew
the
1991
proposed
definition.
See
the
preamble
to
today's
final
rule
and
the
Response
to
Comments
Document
for
the
1997
proposal
for
a
discussion
of
the
revised
proposal.
The
1997
proposal
broadened
the
acceptable
formats
of
SPCC
Plans.
In
1994,
we
finalized
response
plan
requirements.

V
­15
Spill
event
90
Background:
In
1991,
we
proposed
to
revise
the
definition
of
a
spill
event
to
make
it
consistent
with
the
proposed
changes
in
§112.1,
reflecting
the
expanded
scope
of
CWA
jurisdiction.
We
proposed
to
define
a
spill
event
as
a
discharge
of
oil
as
described
in
§112.1(
b)(
1).

Comments:
"`
Spill
event'
should
refer
only
to
discharges
to
navigable
waters."
(28,
31,
101,
165,
L15)
"There
is
a
great
deal
of
confusion
over
the
words:
`spill,
'
`spill
events,
'
and
`discharges,
'
`leak',
etc.
EPA
should
use
this
opportunity
to
define
the
term
`discharge'
as
a
reportable
event
under
40
CFR
110
and
remove
the
term
`spill
event'
from
the
regulations.
The
reason
for
this
is
that
`discharge'
is
the
word
used
in
40
CFR
110,
and
EPA
should
be
consistent
in
the
use
of
this
important
word.
Then
`spills,
'
`leaks,
'
`release,
'
drips,
'
etc.
can
be
reserved
for
those
events
where
oil
escapes
from
some
containment
system,
but
does
not
get
to
water.
This
would
be
a
great
improvement
over
current
terminology."
(121)

Response:
We
have
withdrawn
the
proposed
definition
of
"spill
event,"
and
have
also
deleted
the
term
from
the
rule.
We
take
this
action
because
the
term
is
not
mentioned
in
the
CWA
and
is
unnecessary.
The
term
is
unnecessary
because
the
word
"discharge"
is
adequate.
"Discharge"
is
the
term
used
in
the
CWA.
A
discharge
as
described
in
§112.1(
b)
is
the
same
as
a
spill
event.

V
­16
Storage
capacity
Background:
In
1991,
we
proposed
to
define
storage
capacity
to
clarify
the
necessity
of
counting
container
capacity
­­
not
the
actual
content
­­
in
calculating
the
regulatory
threshold.
We
stated
that
for
determining
the
applicability
of
part
112,
the
storage
capacity
of
a
container
means
the
total
capacity
of
the
container,
whether
the
container
is
filled
with
oil
or
a
mixture
of
oil
and
other
substances.

Comments:
Opposition
to
proposal.
"As
proposed,
if
a
vessel
contains
only
trace
amounts
of
oil,
its
entire
volume
must
be
included."
(28,
31,
58,
67,
85,
86,
95,
101,
102,
103,
106,
113,
165,
167)

Secondary
containment
containers.
"The
extremely
broad
definition
proposed
for
`storage
capacity'
also
could
require
that
a
tank
or
container
that
is
used
to
provide
secondary
containment
be
considered
when
determining
the
storage
capacity
of
a
facility.
This
could
discourage
the
installation
of
containers
for
use
as
secondary
containment
at
small
facilities
that
would
otherwise
be
exempt
from
these
regulations."
(67,
85,
95)

Waste
treatment
facilities.
"Based
on
the
proposed
definition,
the
entire
volume
of
any
container
including
the
non­
usable
space
at
the
top
of
the
tank,
containing
trace
amounts
of
oil
must
be
used
to
determine
applicability
of
these
regulations.
As
a
result,
storage
tanks
used
to
store
or
treat
wastewaters
are
likely
to
have
to
be
considered
when
determining
oil
storage
capacity
since
many
wastewaters
have
incidental
oil
content
prior
to
treatment.
It
is
important
91
to
note
that
the
issue
of
tanks
containing
trace
amounts
of
oil
does
not
apply
only
to
the
petroleum
industry.
It
is
not
uncommon
for
municipal
stormwater
runoff
to
contain
trace
amounts
of
oil
due
to
runoff
from
parking
lots
and
city
streets.
The
proposed
definition
...
could
result
in
these
regulations
being
applicable
to
stormwater
surge
tanks
used
by
POTWs
due
to
the
incidental
oil
content
of
stormwater
runoff."
(67,
72,
95)

Standard
of
measurement.

Bulk
storage
tanks
only.
"The
proposed
definition
...
needs
to
be
amended
so
that
it
is
clear
that
only
tanks
or
containers
meeting
the
definition
of
a
bulk
storage
tank,
and
only
the
oil
storage
capacity
of
that
tank,
need
be
considered."
(67,
175)

Design
capacity.
"Some
electrical
equipment
which
may
fall
under
these
regulations
contain
interior
components
which
reduce
the
volume
of
oil
contained.
The
design,
not
total
capacity
as
might
be
measured
by
the
dimensions
unadjusted
for
these
components,
is
more
appropriately
used
in
this
situation."
(183)

Mixtures.
"The
proposed
definition
of
`storage
capacity'
specifies
that
the
total
capacity
of
a
tank
is
to
be
considered
for
the
purpose
of
this
regulation,
regardless
of
whether
the
tank
stores
oil
or
an
oil
mixture.
We
strongly
believe
this
clarification
should
become
part
of
the
final
rule."
(27)

Oil­
water
separators.
Storage
capacity
should
not
include
the
capacity
of
flowthrough
separators.
(31,
165,
L15)

Volume.
Volume
is
the
proper
measure
of
storage
capacity,
not
total
capacity.
(160)

Working
capacity.
Working
capacity,
"that
is,
the
volume
of
the
tank
used
for
storage,"
should
be
the
standard,
rather
than
shell
capacity.
(86)

Response:
Support
for
proposal.
We
appreciate
commenter
support.

Editorial
changes
and
clarifications.
We
use
the
word
"container"
instead
of
"tank
or
container,"
because
a
tank
is
a
type
of
container.
We
have
clarified
the
definition
to
provide
that
the
storage
capacity
of
a
container
is
the
volume
of
oil
that
the
container
could
hold,
and
have
therefore
substituted
the
words
"shell
capacity"
of
the
container
for
"total
capacity."
This
is
merely
a
clarification,
and
not
a
substantive
change.
We
also
deleted
the
words
"for
purposes
of
determining
applicability
of
this
part,"
because
the
words
were
unnecessary.
We
also
deleted
the
last
phrase
of
the
proposed
definition,
"whether
the
tank
or
container
is
filled
with
oil
or
a
mixture
of
oil
and
other
substances,"
because
the
contents
of
the
container
do
not
affect
the
definition
of
its
shell
capacity.
92
Exclusions
­
small
containers;
waste
treatment
facilities.
Small
containers.
This
definition
is
applicable
to
both
large
and
small
storage
and
use
capacity.
Owners
or
operators
of
small
facilities
above
the
regulatory
threshold
are
subject
to
the
rule,
and
need
to
know
how
to
calculate
their
storage
or
use
capacity.

However,
in
the
applicability
section
of
the
rule,
we
have
excluded
aboveground
or
completely
buried
containers
of
less
than
55
gallons
from
the
scope
of
the
SPCC
rule,
addressing
the
comments
of
those
commenters
who
argued
for
a
minimum
container
size.
See
§112.1(
d)(
5).
A
container
above
that
size
that
is
available
for
use
or
storage
containing
even
small
volumes
of
oil
must
be
counted
in
storage
capacity.

Secondary
containment
containers.
Containers
which
are
used
for
secondary
containment
and
not
storage
or
use,
are
not
counted
as
storage
capacity.

Standard
of
measurement.
In
most
instances
the
shell
capacity
of
a
container
will
define
its
storage
capacity.
The
shell
capacity
(or
nominal
or
gross
capacity)
is
the
amount
of
oil
that
a
container
is
designed
to
hold.
If
a
certain
portion
of
a
container
is
incapable
of
storing
oil
because
of
its
integral
design,
for
example
electrical
equipment
or
other
interior
component
might
take
up
space,
then
the
shell
capacity
of
the
container
is
reduced
to
the
volume
the
container
might
hold.
When
the
integral
design
of
a
container
has
been
altered
by
actions
such
as
drilling
a
hole
in
the
side
of
the
container
so
that
it
cannot
hold
oil
above
that
point,
shell
capacity
remains
the
measure
of
storage
capacity
because
such
alteration
can
be
altered
again
at
will
to
restore
the
former
storage
capacity.
When
the
alteration
is
an
action
such
as
the
installation
of
a
double
bottom
or
new
floor
to
the
container,
the
integral
design
of
the
container
has
changed,
and
may
result
in
a
reduction
in
shell
capacity.
We
disagree
that
operating
volume
should
be
the
measurement,
because
the
operating
volume
of
a
tank
can
be
changed
at
will
to
below
its
shell
capacity.

The
keys
to
the
definition
are
the
availability
of
the
container
for
drilling,
producing,
gathering,
storing,
processing,
refining,
transferring,
distributing,
using,
or
consuming
oil,
and
whether
it
is
available
for
one
of
those
uses
or
whether
it
is
permanently
closed.
Containers
available
for
one
of
the
above
described
uses
count
towards
storage
capacity,
those
not
used
for
these
activities
do
not.
Types
of
containers
counted
as
storage
capacity
would
include
flow­
through
separators,
tanks
used
for
"emergency"
storage,
transformers,
and
other
oil­
filled
equipment.

Waste
treatment
facilities.
We
agree
with
the
commenter
that
a
facility
or
part
thereof
(except
at
an
oil
production,
oil
recovery,
or
oil
recycling
facility)
used
exclusively
for
wastewater
treatment
and
not
to
meet
any
part
112
requirement
should
not
be
considered
storage
capacity
because
wastewater
treatment
is
neither
storage
nor
use
of
oil.
Therefore,
we
have
exempted
such
facilities
or
parts
thereof
from
the
rule.
However,
note
that
certain
parts
of
such
facilities
may
continue
to
be
subject
to
the
rule.
See
the
discussion
under
§112.1(
d)(
6).

V
­17
Wetlands
(see
also
"navigable
waters.")
93
Background:
In
1991,
we
proposed
to
define
wetlands,
a
term
used
in
the
definition
of
navigable
waters.
We
noted
that
the
proposed
definition
conformed
with
the
part
110
definition.

Comments:
1987
Wetlands
Manual.
"The
definition
of
wetlands
should
conform
to
the
definition
in
the
`Federal
Manual
for
Identifying
and
Delineating
Jurisdictional
Wetlands'."
"We
strongly
urge
that
the
definition
of
`wetlands'
proposed
in
this
rulemaking
be
either
deleted
or
scaled
back
to
the
present
definition
set
forth
in
40
CFR
230.3.
We
suggest
that
deferral
is
required
because
the
effort
of
the
four
agencies
has
received
much
more
public
scrutiny
than
this
proposed
rule,
and
EPA
will
have
a
better
record
upon
which
to
base
a
definition
that
covers
the
entire
range
of
programs,
rather
than
one
specific
program
as
here."
(64,
73,
78,
106,
145,
167,
175)

Examples
of
wetlands.
"The
`Wetlands'
definition
includes
a
series
of
examples
which
may
not
be
appropriate
or
correct
and
should
be
deleted."
(64)

Phreatophytes.
"
Phreatophytes,
hydric
soils,
and
saturation
should
be
a
part
of
the
definition."
(167)

Expansion
of
definition.
The
proposed
definition
would
significantly
expand
wetlands
beyond
what
was
in
the
delineation
manual.
(73,
106)
"...(
W)
e
deserve
to
know
exactly
what
the
rules
hold
in
store
for
us.
The
jurisdiction
of
this
regulation
must
be
welldefined
incorporating
vague
references
to
`wetlands'
and
`sensitive
ecological
area'
is
not
acceptable
to
the
agriculture
industry
and
will
no
doubt
pose
serious
enforcement
problems
to
the
Agency."
(139)

NPDES
program.
"Again,
the
protections
provided
by
a
regulatory
permit
program,
as
in
the
wetland
regulations,
are
not
necessary
under
the
OPA,
which
seeks
to
identify
and
preclude
the
discharge
of
oil
to
`waters'
from
high
risk
bulk
oil
storage.
Wetlands
and
other
aquatic
sites
are
adequately
protected
under
the
Clean
Water
Act.
...
(N)
avigable
waters
alone
should
serve
as
the
jurisdictional
trigger
under
the
OPA."
(35)

Response:
Examples
of
wetlands.
The
examples
listed
in
the
definition
are
intended
to
help
the
reader
with
guidelines
to
identify
wetlands.
While
the
examples
generally
represent
types
of
wetlands,
they
are
not
intended
to
be
a
categorical
listing
of
such
wetlands.
There
may
be
examples
listed
that
under
some
circumstances
do
not
constitute
wetlands.
We
believe
that
the
1987
Wetlands
Manual
is
a
useful
source
material
for
wetlands
guidance.
It
would
be
impossible
to
specify
in
a
rule
every
type
of
situation
where
wetlands
occur.
The
examples
listed
in
the
definition
are
not
exclusive,
but
provide
help
in
clarifying
what
may
be
a
wetland.

Expansion
of
definition.
We
disagree
that
the
definition
expands
the
term
"wetlands"
beyond
what
is
in
the
1987
Wetlands
Manual.
It
does
nothing
to
substantively
expand
our
jurisdiction
over
wetlands.
94
Rulemaking
process.
We
disagree
that
we
should
not
define
"wetlands."
While
the
NPDES
program
may
define
wetlands,
the
NPDES
program
and
the
SPCC
program
have
different
purposes,
and
a
definition
is
needed
for
part
112.
The
definition
is
necessary
to
supply
guidance
to
the
regulated
public.
The
definition
of
"navigable
waters"
includes
wetlands,
as
defined
in
§112.2,
because
wetlands
are
waters
of
the
United
States.
We
note
that
40
CFR
230.3
and
the
delineation
manual
serve
different
purposes
than
part
112.
We
believe
that
it
is
important
to
base
the
definition
on
the
part
110
definition,
because
of
the
integral
connection
between
parts
110
and
112.

V
­
18
Other
definitions
Background:
Several
commenters
suggested
definitions
which
we
did
not
propose.

Comments:
Consistency
in
definitions.
In
general,
we
should
make
the
definitions
in
part
112
consistent
with
corresponding
definitions
provided
in
other
regulations.
There
is
no
justification
for
redefining
terms
specific
to
the
SPCC
regulation
and
to
do
so
would
cause
"significant
confusion."
(167)

Specific
definitions
requested.

Connecting
line.
(113)

Contingency
plan.
(82)

Flow­
through
process
tank.
We
should
define
flow­
through
process
tank
in
§112.2.
(28,
31,113,
165,
L15)

Good
engineering
practice.
(33)

Impervious.
(27,
L12)

Oil
production
facility
transfer
operation.
We
should
include
a
definition
of
oil
production
facility
transfer
operation
in
§112.2.
(L12)

Prevention,
response,
mitigation.
We
should
define
the
terms
prevention,
response,
and
mitigation:
provides
suggested
text.
(121)

Professional
Engineer.
(43)

Response:
Consistency
in
definitions.
We
agree
that
definitions
in
part
112
should
be
consistent
with
corresponding
definitions
in
other
regulations
when
it
is
appropriate.
However,
sometimes
differing
definitions
are
necessary
to
serve
differing
program
goals.
Specific
definitions
requested.
For
the
suggested
definitions
not
proposed,
a
dictionary
or
industry
definition
is
sufficient.
95
Transfer
operation.
A
transfer
operation
is
one
in
which
oil
is
moved
from
or
into
some
form
of
transportation,
storage,
equipment,
or
other
device,
into
or
from
some
other
or
similar
form
of
transportation,
such
as
a
pipeline,
truck,
tank
car,
or
other
storage,
equipment,
or
device.
96
Category
VI
­
Preparing
and
implementing
Plans.

VI
­
A:
Time
frames
for
preparing
and
implementing
Plans
­
§112.3(
a),
(b),
(c)

Background:
Section
112.3(
a)
of
the
current
rule
requires
the
owner
or
operator
of
a
facility
existing
on
or
before
the
effective
date
of
the
rule
that
is
subject
to
the
rule
to
prepare
and
implement
a
Plan
within
one
year
after
the
effective
date
of
the
rule.
In
1991,
we
proposed
in
§112.3(
a)
to
require
an
owner
or
operator
of
a
facility
in
operation
on
or
before
the
effective
date
of
the
rule
to
prepare
and
implement
a
Plan
within
60
days
following
that
date.

Section
112.3(
b)
of
the
current
rule
requires
the
owner
or
operator
of
a
facility
becoming
operational
after
the
effective
date
of
the
rule
to
prepare
a
Plan
within
six
months
after
the
facility
begins
operations
and
implement
it
within
one
year.
In
1991,
we
proposed
to
require
the
owner
or
operator
of
a
facility
beginning
operations
more
than
60
days
after
publication
of
the
rule
to
prepare
and
fully
implement
an
SPCC
Plan
before
beginning
operations.

Section
112.3(
c)
of
the
current
rule
requires
an
owner
or
operator
of
a
mobile
or
portable
facility
to
prepare
and
implement
a
Plan
as
required
under
§112.3(
a),
(b),
and
(d).
In
1991,
we
proposed
to
require
an
owner
or
operator
of
a
mobile
or
portable
facility
to
prepare,
implement,
and
maintain
an
SPCC
Plan
as
required
under
proposed
§112.3(
a),
(b),
and
(d),
noting
that
these
owners
or
operators
would
not
need
to
prepare
a
new
Plan
each
time
the
facility
is
moved
to
a
new
location.

Comments:
Time
period
to
prepare
and
implement
a
Plan.

Support
for
proposal.
"The
proposed
provision
...
requiring
that
`a
facility
SPCC
Plan
be
prepared
and
fully
implemented
before
a
facility
begins
operations...
'
is
commendable."
"This
is
protective
of
the
environment
and
consistent
with
many
other
environmental
requirements."
(43,
62,
80,
90,
121,
181,
185,
and
L11)

Opposition
to
proposal.
Re
proposed
§112.3(
a):
"Sixty
days
is
not
a
practical
time
for
compliance
for
Appalachian
producers,
who
literally
have
thousands
of
sites
throughout
the
seven
Appalachian
states."
Re
proposed
§112.3(
b):
"It
is
recommended
that
the
language
of
current
§112.3(
b),
which
allows
six
months
for
the
preparation
of
the
plan,
be
retained."
(3,
23,
27,
34,
36,
42,
58,
66,
68,
71,
101,
107,
111,
113,
116,
134,
189)

Implementation
and
training.
Our
proposal
is
impracticable
because
it
does
not
allow
new
facility
owners
or
operators
enough
time
to
implement
the
Plan
and
train
the
appropriate
personnel.
(66)

Acquired
facilities.
"BFI
would
also
ask
the
EPA
to
clarify
how
it
would
interpret
this
provision
where
an
acquisition
is
being
made.
These
acquired
facilities
under
prior
ownership
may
not
have
been
aware
of
the
SPCC
rule
and
its
provisions
and
hence
97
may
not
have
put
a
plan
into
place.
BFI
would
propose
to
the
EPA
that
this
does
not
constitute
a
`new
facility'
but
an
existing
facility
and
that
operations
need
not
cease,
while
notification
to
EPA
is
being
made
and
an
SPCC
Plan
is
developed
and
implemented."
(23)

Alternate
time
frames
suggested
Existing
Plans.

180
days.
(28,
36,
67,
68,
79,
85,
90,
91,
102,
107,
111,
116,
128,
134,
141)

Next
triennial
review.
"If
EPA
insists
on
making
these
small
facilities
comply
with
the
proposed
changes,
then
they
should
only
be
required
to
comply
at
the
time
of
routine
plan
recertification,
not
before."
(29,
58,
62,
78,
83,
101,
113,
116,
141,
145,
1164,
185,
189,
L2,
L14)

Three
years
plus
seven
years.
"A
more
realistic
compliance
period
would
be
a
minimum
of
three
years
for
the
preparation
of
plans
with
an
additional
seven
years
for
the
completion
of
necessary
construction,
if
any."
(98)

180
days
or
after
updates.
"We
suggest
that
plans
be
allowed
to
be
updated
whenever
a
change
occurs
or
when
the
next
triennial
review
would
occur,
whichever
is
sooner."
(71)

5­
7
years.
"A
five
to
seven
year
phase­
in
compliance
schedule
similar
to
the
approach
taken
with
EPA's
underground
storage
tank
program
would
be
a
more
reasonable
and
achievable
approach."
(92)

New
Plans.

180
days.
"It
is
recommended
that
the
language
of
current
§112.3(
b),
which
allows
six
months
for
the
preparation
of
the
plan,
be
retained."
(101)

Cost.
The
costs
associated
with
the
proposal
"cannot
be
justified
in
terms
of
the
CWA
or
in
anticipated
benefits
to
the
public.
First,
the
start
up
volume
associated
with
beginning
operations
at
an
onshore
oil
production
facility
is
small.
Thus,
any
discharge
associated
with
commencement
of
operation
would
also
be
small.
Second,
the
history
of
performance
in
the
start
up
of
a
well
is
very
good,
both
in
terms
of
industry's
standards
and
in
terms
of
supervision
by
State
regulatory
authorities.
Thus,
even
the
small
discharge
which
might
occur
is
unlikely.
Third,
the
cost
associated
with
the
engineer
is
disproportionately
high
when
his
services
at
a
small
operation
(with
low
risk)
are
compared
to
similar
costs
at
a
large
facility
(where
the
risk
is
much
higher).
"
(42)
98
Extensions.
We
should
grant
an
automatic
extension
of
six
months,
at
a
minimum,
if
the
RA
does
not
decide
within
30
days
of
receiving
the
extension
request.
If
an
RA
grants
or
denies
an
extension,
we
should
require
a
Professional
Engineer
(PE)
to
certify
that
the
RA's
decision
was
made
in
accordance
with
"good
engineering
practice."
(33,
42,
66,110,
133,
167,
L12)

Small
facilities.
Criticizing
proposed
requirement
to
have
Plan
developed
and
implemented
before
beginning
operations,
"...
BFI
urges
that
small
facilities
(e.
g.,
those
with
10,000
gallons
or
less
of
above
ground
oil
storage)
should
be
eligible
for
a
reasonable
time
period
to
develop
and
implement
this
plan
while
operations
occur.
Although
the
EPA
provided
the
potential
for
extensions
from
the
Regional
Administrator,
these
extensions
are
not
automatic
and
the
sheer
burden
to
the
Regional
Administrator
from
numerous
small
facility
requests
would
be
unmanageable."
(23)

Mobile
facilities.

General
Plans.
We
should
allow
a
"strong
generic
spill
contingency
plan"
for
a
mobile
oil
and
gas
production
facility
until
the
owner
or
operator
can
prepare
and
implement
the
SPCC
Plan.
Seeking
an
extension
from
the
Regional
Administrator
(RA)
could
delay
start­
up,
and
we
should
require
the
owner
or
operator
of
a
mobile
facility
to
prepare
an
SPCC
Plan
within
60
days
after
the
facility
begins
operations.
(68)
Commends
EPA
for:
"Retaining
provisions
in
Section
112.3(
c)
that
allow
owners/
operators
of
onshore
and
offshore
mobile
or
portable
facilities
to
prepare
a
general
plan
for
such
a
facility
so
that
a
new
plan
need
not
be
prepared
each
time
a
facility
is
moved
to
a
new
site."
(97)

Multi­
well
drilling
program.
"We
question
whether
plan
updates
will
be
required
in
a
field
where
a
multi­
well
drilling
program
is
underway.
Updates
of
the
plan
should
be
required
only
after
the
drilling
program
is
complete."
(167)

No
Plans.
The
definition
of
facility
"contemplates
a
fixed
structure,
or
unit,
which
serves
a
purpose
at
the
place
where
it
is
fixed.
Where
equipment
is
mobile,
its
physical
surroundings
are
subject
to
change.
Conceivably,
a
SPCC
Plan
for
a
mobile
`facility'
would
have
to
be
amended
each
time
the
mobile
equipment
is
moved.
This
is
likely
to
be
an
unworkable
requirement.
For
these
reasons,
mobile
equipment
should
not
be
considered
a
facility
for
purposes
of
SPCC
regulations."
(188)

NPDES
coordination.
We
should
coordinate
SPCC
regulation
with
the
National
Pollutant
Discharge
Elimination
System
(NPDES)
storm
water
discharge
permit
system.
(76)

Start
of
operations.
"Since
many
facilities
initially
become
partially
operational,
defining
the
start
of
operations
is
not
always
clear.
A
better
approach
would
be
to
require
that
a
response
team
be
in
place
and
the
notification
portion
of
the
plan
be
completed
prior
to
99
beginning
operations
and
the
entire
plan
to
be
completed
within
six
(6)
months
of
startup."
(36)

"Submittal."
We
should
clarify
the
term
submittal
in
the
Preamble,
because
we
do
not
require
facility
owners
or
operators
to
submit
SPCC
Plans
to
us
under
the
regulation.
(95,
101)

Response:
Time
period
to
prepare
and
implement
a
Plan.

Support
for
proposal.
We
appreciate
the
expressions
of
support
for
our
proposal.
We
have
been
persuaded
by
commenters
that
a
longer
phase­
in
period
than
60
days
is
required
for
facilities
currently
in
operation
or
about
to
become
operational
within
one
year
after
the
effective
date
of
this
rule.

Facilities
currently
in
operation.
For
a
facility
in
operation
on
the
effective
date
of
this
rule,
we
changed
the
dates
in
the
proposed
rule
for
preparation
and
implementation
of
plans
from
60
days
to
a
maximum
of
one
year
to
accord
with
the
time
frames
in
the
current
rule.
The
owner
or
operator
of
a
facility
in
operation
on
the
effective
date
of
this
rule
will
have
6
months
to
amend
his
Plan
and
must
fully
implement
any
amendment
as
soon
as
possible,
but
within
one
year
of
the
effective
date
of
the
rule
at
the
latest.
The
owner
or
operator
of
a
facility
which
has
had
a
discharge
as
described
in
§112.
1(
b),
or
reasonably
could
be
expected
to
have
one,
already
has
an
obligation
to
prepare
and
implement
a
Plan.

Facilities
becoming
operational
within
one
year
after
the
effective
date
of
the
rule
(13
months
following
publication
in
the
Federal
Register).
If
you
begin
operations
on
or
after
the
effective
date
of
the
rule
through
one
year
after
the
effective
date
of
this
rule
(the
effective
date
of
the
rule
is
30
days
after
the
Federal
Register
publication
date),
you
will
have
until
one
year
from
the
effective
date
of
this
rule
to
prepare
and
implement
your
Plan.
In
other
words,
if
the
rule
becomes
effective
on
January
1,
and
you
begin
operations
on
January
2,
you
must
prepare
and
implement
your
Plan
by
January
1
of
the
following
year.
If
you
begin
operations
on
June
30,
you
still
have
until
January
1
of
the
following
year
to
prepare
and
implement
your
plan.
If
you
begin
operations
on
December
31,
you
still
have
until
January
1
(the
next
day)
of
the
following
year
to
prepare
and
implement
your
Plan.
The
rationale
for
the
time
frame
in
the
rule
is
that
you
will
have
had
notice
of
the
Plan
preparation
and
implementation
requirements
from
the
publication
date
of
the
rule,
a
period
of
30
days
plus
one
year.
In
addition,
you
would
already
have
had
notice
of
the
general
requirement
for
preparation
of
an
SPCC
Plan
from
the
current
part
112
regulations.
Therefore,
the
owner
or
operator
of
a
facility
planning
to
become
operational
within
one
year
after
the
effective
date
of
this
rule
should
start
working
on
his
Plan
in
time
to
have
it
fully
implemented
within
the
year.
100
New
facilities.
The
owner
or
operator
of
a
facility
that
becomes
operational
more
than
one
year
after
the
effective
date
of
this
rule
must
prepare
and
implement
a
Plan
before
beginning
operations.
Experience
with
the
implementation
of
this
regulation
shows
that
many
types
of
failures
occur
during
or
shortly
following
startup
and
that
virtually
all
prevention,
containment,
and
countermeasure
practices
are
part
of
the
facility
design
or
construction.

A
year
phase­
in
period
is
in
line
with
legitimate
business
and
investment
expectations.
It
allows
a
reasonable
period
of
time
for
facilities
to
undertake
necessary
constructions,
purchases
of
equipment,
or
to
effect
changes
of
procedures.
And
again,
the
general
requirement
for
preparation
of
a
Plan
already
exists
in
part
112,
so
new
facilities
should
already
have
been
aware
of
the
need
for
a
Plan.

Acquired
facilities.
For
SPCC
purposes,
we
consider
acquired
facilities
as
facilities
that
are
already
operating
rather
than
new
facilities
because
these
facilities
must
already
have
SPCC
Plans
if
they
exceed
applicable
thresholds.

Cost.
We
disagree
that
the
rule
places
a
disproportionate
impact
on
the
regulated
facilities,
whether
large
or
small.
Most
of
the
requirements
of
the
rule
are
practices
that
many
facilities
would
follow
whether
the
rule
required
them
or
not.
Not
only
have
we
fully
assessed
the
costs
for
small
entities,
but
the
applicability
criteria
for
part
112
also
eliminate
a
number
of
small
businesses
from
SPCC
coverage.
While
amounts
of
oil
stored
may
be
small
at
some
facilities,
even
a
small
discharge
may
be
disastrous
to
the
environment.
We
also
disagree
that
small
facility
start­
ups
cause
fewer
discharges
than
start­
ups
at
large
facilities.
Our
experience
shows
the
contrary;
and
the
commenter
presents
no
evidence
for
his
assertion.

We
also
disagree
that
the
cost
of
PE
certification
at
a
small
facility
is
disproportionate
to
that
of
certification
at
a
large
facility.
A
small
facility
is
more
likely
to
require
a
simpler,
less
expensive
Plan
that
costs
less
to
prepare
and
implement
than
a
Plan
at
a
large
facility.

Finally,
we
disagree
that
we
should
treat
large
and
small
facilities
differently
under
§112.
3(
b).
Either
type
of
facility
may
be
the
source
of
a
discharge
as
described
in
§112.1(
b).

Extensions.
While
we
have
extended
the
time
period
for
compliance,
we
understand
that
some
facilities
may
still
need
extensions
of
time
to
comply.
Extensions
may
be
necessary
to
secure
necessary
manpower
or
equipment,
or
to
construct
necessary
structures.
If
you
are
an
owner
or
operator
and
an
extension
is
necessary,
you
may
seek
one
under
§112.3(
f).
If
no
Plan
amendments
are
necessary
after
you
review
today's
rule,
you
must
maintain
your
current
Plan
and
cross­
reference
its
elements
to
the
redesignated
requirements.
We
disagree
that
we
should
grant
an
automatic
extension
of
six
months,
at
a
minimum,
if
the
RA
does
not
decide
within
30
days
of
receiving
the
extension
request
because
compliance
with
the
rest
of
the
Plan
that
is
not
101
affected
by
the
extension
request
remains
in
effect.
We
also
disagree
that
we
should
require
a
Professional
Engineer
(PE)
to
certify
that
the
RA's
decision
was
made
in
accordance
with
"good
engineering
practice."
The
RA
has
the
assistance
of
PEs
when
necessary.

Mobile
facilities.
We
agree
that
the
physical
surroundings
of
mobile
facilities
are
subject
to
change.
However,
we
disagree
that
changing
physical
surroundings
should
exempt
mobile
facilities
from
the
rule.
Mobile
facilities
may
have
"general"
Plans
and
need
not
prepare
a
new
Plan
each
time
the
facility
is
moved
to
a
new
site.
When
a
mobile
facility
is
moved,
it
must
be
located
and
installed
using
the
spill
prevention
practices
outlined
in
the
Plan
for
the
facility.

Mobile
facilities
currently
in
operation
are
assumed
to
have
implemented
Plans
already,
because
they
are
currently
legally
required
to
do
so.
Both
new
and
existing
mobile
facilities
must
have
Plans
prepared
and
fully
implemented
before
operations
may
begin.
If
after
your
review
of
today's
rule,
you
decide
that
no
amendment
to
your
Plan
is
necessary,
except
for
cross­
referencing,
you
may
continue
to
operate
under
your
existing
Plan,
but
you
must
promptly
cross­
reference
the
provisions
in
the
Plan
to
the
new
format.
Extension
requests
under
§112.3(
f)
are
also
available
for
mobile
facilities
under
the
proper
conditions.

Multi­
well
drilling
programs.
It
is
not
necessary
to
amend
the
Plan
every
time
you
drill
a
well
in
a
field
containing
multiple
wells.
A
general
Plan
will
suffice.

NPDES
coordination.
We
allow
use
of
a
Best
Management
Practice
Plan
(BMP)
prepared
under
an
NPDES
permit
to
serve
as
an
SPCC
Plan
if
the
BMP
meets
all
of
part
112
requirements.
When
if
does
not,
it
may
be
supplemented.
Therefore,
we
end
duplicate
paperwork
requirements.
Furthermore,
under
§§
112.8(
c)(
3)
and
112.9(
b)(
1),
an
owner
or
operator
may,
at
his
option,
use
records
required
under
NPDES
permit
regulations
to
record
stormwater
bypass
events
for
SPCC
recordkeeping
purposes.

Small
facilities.
With
the
extended
time
line
we
have
provided,
all
facilities,
large
or
small,
have
adequate
notice
and
time
in
which
to
prepare
and
implement
a
Plan.

Start
of
operations.
Start
of
operations
is
when
you
begin
to
store
or
use
oil
at
a
facility.
Often
this
may
be
a
testing
or
calibration
period
prior
to
start
up
of
normal
operations.
With
the
extended
time
line
we
have
provided,
no
response
team
is
required,
but
such
a
team
may
be
a
good
engineering
practice.
At
a
minimum,
you
must
prepare
and
implement
a
Plan
as
required
by
this
rule.

"Submittal."
The
word
submittal
was
incorrectly
referred
to
in
the
rule.
See
56
FR
54618.
The
commenters
are
correct
that
as
a
general
rule,
we
do
not
require
any
owner
or
operator
to
submit
a
Plan.
An
owner
or
operator
may
be
required
to
submit
a
Plan
in
certain
circumstances,
such
as
when
a
facility
discharges
oil
over
the
threshold
amount
specified
in
§112.
4(
a),
or
after
on­
site
inspection
of
the
facility.
102
Training
and
implementation.
We
disagree
that
it
is
impracticable
to
train
the
appropriate
personnel
before
start­
up.
We
note,
however,
that
we
have
extended
the
time
frame
for
Plan
preparation
and
implementation
beyond
what
we
proposed.
Thus,
many
facilities
will
have
more
time
for
training
and
implementation,
and
all
facilities
will
be
on
notice
of
the
new
time
frames,
thereby
allowing
time
to
plan
training
and
implementation
before
starting
operations.
103
VI
­
B:
Good
engineering
practice
­
§§
112.3(
d)

Background:
In
1991,
we
noted
that
good
engineering
practice
is
the
applicable
standard
for
all
SPCC
Plans.
See
§§
112.3(
d)
and
112.7.
We
noted
further
that
this
principle
requires
an
owner
or
operator
to
incorporate
appropriate
provisions
of
applicable
regulations,
standards,
and
codes
into
the
Plan.

Comments:
Support
for
application
of
good
engineering
practice.
"Chevron
supports
the
flexibility
of
the
current
SPCC
Program,
which
has
allowed
petroleum
industry
operations
to
adapt
SPCC
provisions
at
a
particular
site
in
accordance
with
`good
engineering
practice'."
(96,
97)

Deviations.
"...(
W)
e
recommend
that
EPA
include
in
the
applicability
provision
of
the
proposal,
proposed
§112.1,
a
statement
that
the
purpose
of
the
rule
is
to
protect
navigable
waters
from
the
risk
of
oil
contamination
and
that
implementation
of
the
rule
is
based
on
good
engineering
practice.
Specifically,
we
urge
that
this
section
provide
that
failure
to
conform
to
the
specific
requirements
of
the
rule
shall
not
be
a
violation
where
the
owner
or
operator
can
demonstrate,
in
the
exercise
of
good
engineering
practice,
either
that
the
alternative
practices
provide
adequate
protection
against
a
reasonable
risk
of
discharge
to
navigable
waters
or
that
compliance
with
the
requirements
would
not
contribute
to
protecting
navigable
water
from
a
reasonable
risk
of
discharge."
(125,
170)

Industry
standards.
"...(
I)
t
is
not
always
feasible
or
consistent
with
good
engineering
practice
to
mandate
the
same
requirements
for
every
facility."
We
should
rely
upon
the
discretion
of
local
fire
regulatory
authorities,
as
we
already
recognize
the
model
codes
of
such
authorities
as
consistent
with
good
engineering
practice.
We
should
recognize
the
spill
and
leak
prevention
methods
of
approved
nationally
recognized
regulatory
organizations
as
protection
equivalent
to
our
underground
storage
tank
(UST)
standards.
Recommending
such
industry
standards
to
owners
or
operators
as
guidance
provides
neither
end
users
nor
"entities
charged
with
enforcing
EPA
standards"
with
enough
specific
guidance.
We
should
recognize
that
the
NFPA,
BOCA,
and
UFC
historically
have
regulated
aboveground
storage
tanks
(ASTs)
of
less
than
6,000
gallons
per
tank
and
18,000
gallons
per
site.
Industry
standards
resulting
from
these
regulations
provide
protection
that
is
equivalent
to
our
standards.
(65)
"If
EPA
wants
the
use
of
codes
and
standards
to
become
part
of
part
112,
then
it
must
say
so
in
the
regulation
(not
the
preamble).
It
must
also
say
which
codes
will
be
required
and
under
what
circumstances
they
will
be
required.
You
cannot
be
vague
about
this."
(121)

PE
rule
certification.
"At
a
minimum,
such
rules
[SPCC]
must
contain
a
certification
by
a
Professional
Engineer
that
the
rule
and
preamble
have
been
reviewed
by
the
certifying
P.
E.
and
represents
Good
Engineering
Practice."
(110)
We
should
clarify
our
aim
of
grounding
the
rule
on
good
engineering
practice.
(125)

Response:
Support
for
application
of
good
engineering
practice.
We
appreciate
commenter
support.
We
have
maintained
good
engineering
practice
as
the
standard
by
104
which
to
judge
the
propriety
of
various
operating
procedures,
equipment,
systems,
and
installations
at
SPCC
facilities.
Good
engineering
practice
may
include
use
of
industry
standards.

Deviations.
The
purpose
of
the
rule
is
"to
prevent
the
discharge
of
oil
from
nontransportation
related
onshore
and
offshore
facilities
into
or
upon
the
navigable
waters
of
the
States
or
adjoining,
shorelines,
or
into
or
upon
the
waters
of
the
contiguous
zone,
or
in
connection
with
activities
under
the
Outer
Continental
Shelf
Lands
Act
or
the
Deepwater
Port
Act
of
1974,
or
that
may
affect
resources
belonging
to,
appertaining
to,
or
under
the
exclusive
management
authority
of
the
United
States
(including
resources
under
the
Magnuson
Fishery
Conservation
and
Management
Act.)."
40
CFR
112.1(
a)(
1).

In
§112.7(
a)(
2)
of
the
final
rule,
we
permit
deviations
from
most
of
the
substantive
requirements
of
the
rule
when
the
facility
owner
or
operator
can
explain
his
reasons
for
nonconformance,
and
can
provide
equivalent
environmental
protection
by
other
means.
Deviations
from
secondary
containment
requirements
must
be
based
on
impracticability.
40
CFR
112.7(
d).

Good
engineering
practice.
As
we
noted
in
the
1991
preamble
(at
56
FR
54617­
18),
good
engineering
practice
"will
require
that
appropriate
provisions
of
applicable
codes,
standards,
and
regulations
be
incorporated
into
the
SPCC
Plan
for
a
particular
facility."
We
agree
with
the
commenter
that
the
rule
needs
more
specificity
in
this
regard.
Therefore,
we
have
amended
§112.3(
d)(
1)(
iii)
to
specifically
include
consideration
of
applicable
industry
standards
as
an
element
of
the
PE's
attestation
that
the
Plan
has
been
prepared
in
accordance
with
good
engineering
practice.
We
reiterate
today,
as
we
did
in
1991,
that
consideration
of
applicable
industry
standards
is
an
essential
element
of
good
engineering
practice.
Industry
standards
include
industry
regulations,
standards,
codes,
specifications,
recommendations,
recommended
practices,
publications,
bulletins,
and
other
materials.
(See
§112.7(
a)(
1)
and
(j).)
The
owner
or
operator
must
specifically
document
any
industry
standard
used
in
a
Plan
to
comply
with
this
section.
The
documentation
should
include
the
name
of
the
industry
standard,
and
the
year
or
edition
of
that
standard.
However,
as
discussed
above,
we
have
chosen
not
to
incorporate
specific
industry
standards
into
the
rule.

Industry
standards.
We
agree
that
"it
is
not
always
feasible
or
consistent
with
good
engineering
practice
to
mandate
the
same
requirements
for
every
facility."
Therefore,
we
provide
the
owner
or
operator
with
authority
to
deviate
from
most
of
the
rule's
substantive
requirements.
See
§112.7(
a)(
2)
and
(d).
We
also
encourage
the
use
of
industry
standards
when
appropriate,
instead
of
prescribed
frequencies
for
inspections
and
tests.

PE
rule
certification.
We
disagree
that
a
PE
should
certify
our
rulemakings
because
such
certification
would
not
improve
the
rulemaking
process.
However,
we
do
have
the
advice
of
PEs
to
help
us
with
the
process
of
rulemaking.
105
VI­
B­
1
Industry
standards
Comments:
Specific
standards.
If
we
want
to
incorporate
industry
codes
and
standards
into
part
112,
then
we
should
specify
which
codes
and
circumstances.
(121)

Industry
standards
inappropriate.
"Further,
EPA
...
recommends
Good
Engineering
Practice
including
`appropriate
provisions
of
applicable
codes,
standards,
and
regulation
be
incorporated
into
the
SPCC
Plans
for
a
particular
facility.
'
Typically
these
provisions
require
electricity.
However,
many
existing
tanks
do
not
have
and
never
will
have
electricity.
Also,
many
new
E&
P
facilities
will
not
have
electricity
available
because
of
the
remoteness
of
the
facilities.
Further,
I
am
concerned
about
who
will
make
the
decision
as
to
which
are
`appropriate
provisions'.
...(
A)
n
industry
P.
E.,
after
due
consideration
and
visit
to
a
facility,
may
be
overruled
by
a
non­
engineer
as
to
what
constitutes
Good
Engineering
Practice.
This
is
an
abuse
of
bureaucratic
discretion
and
makes
a
mockery
of
State
licensing
procedures."
(110)

Response:
Specific
standards.
While
we
encourage
the
use
of
industry
standards
where
applicable,
we
are
not
requiring
an
owner
or
operator
to
comply
with
specific
industry
standards
or
codes.
Complying
with
industry
standards
or
codes
may
be
inappropriate
under
facility­
specific
circumstances.
Also,
were
we
to
incorporate
standards
and
codes
into
part
112,
these
documents
may
become
outdated
before
we
could
revise
the
rule.
Further,
if
we
incorporate
a
specific
edition
of
a
standard
or
code
into
part
112,
we
may
prevent
the
application
of
advanced
discharge
prevention
practices
and
technologies.

Industry
standards
inappropriate.
We
do
recommend
that
an
owner
or
operator
consider
applicable
standards
and
codes
at
existing
and
new
facilities.
This
approach
allows
an
owner
or
operator
the
flexibility
to
select
a
system
or
procedure
that
reflects
good
engineering
practice.
We
have
relegated
all
recommendations
for
the
preamble
and
other
guidance
documents.
In
the
final
rule,
we
have
amended
§112.3(
d)
to
specifically
include
consideration
of
applicable
industry
standards
as
an
element
of
the
PE's
attestation
that
the
Plan
has
been
prepared
in
accordance
with
good
engineering
practice.

VI
­
C
PE
certification
requirement
­
§112.3(
d)

Background:
In
§112.3(
d)
of
the
current
rule
requires
that
a
PE
review
and
certify
an
SPCC
Plan.
Section
112.3(
d)
provides
that
in
certifying
the
Plan,
the
PE
(having
examined
the
facility
and
being
familiar
with
part
112
provisions)
attests
that
"the
SPCC
Plan
has
been
prepared
in
accordance
with
good
engineering
practices."
In
1991,
we
proposed
to
add
specificity
in
the
rule
to
the
elements
to
which
the
PE
attests
in
certifying
an
SPCC
Plan.
These
elements
were
that:
the
PE
was
familiar
with
part
112
requirements;
he
had
visited
and
examined
the
facility
for
which
he
certified
the
Plan;
the
Plan
was
prepared
in
accordance
with
good
engineering
practice
and
part
112;
required
testing
was
complete;
and
the
Plan
was
adequate
for
the
facility.
106
Comments:
Support
for
certification
requirement.
PE
Plan
review
and
certification
ensures
that
the
facility
follows
good
engineering
practice
and
has
an
adequate
Plan.
We
should
retain
the
current
§112.3(
d)
text.
(54,
67,
86,
97,
102,
105,
118,
155,
164,
182)

Competence.
We
should
require
that
the
PE
be
qualified
by
education,
training,
or
experience,
since
"most
States
prohibit
licensees
from
engaging
in
work
the
engineer
is
not
competent
or
qualified
to
perform."
(L25)

Opposition
to
certification
requirement.

Cost.
"There
are
elements
of
the
plan
that
a
PE
is
typically
not
qualified
to
do,
for
example
vulnerability
analyses,
and
yet
all
plans
are
to
be
certified
by
someone
with
PE
registration.
This
over­
emphasis
on
engineering
qualifications
is
misplaced
and
will
not
guarantee
one
measure
of
extra
protection
for
the
environment.
Such
requirements
add
significantly
to
the
cost
of
preparing
SPCC
plans
without
offsetting
benefits."
(109,
162,
L2)

Design
v.
Plan
preparation.
"EPA
must
not
confuse
facility
design
with
SPCC
plan
preparation.
While
an
engineer
may
need
to
design
the
facility
(e.
g.,
tanks,
piping,
etc.)
A
scientist
is
equally
capable
of
describing
the
facility
and
developing
appropriate
emergency
response
procedures."
(107,
176)

Lack
of
expertise.
A
PE
may
not
be
"trained
in
the
SPCC
regulations"
and
may
lack
the
ability
to
apply
part
112
requirements
in
the
field.
(70)
We
should
require
certification
by
persons
possessing
"the
necessary
technical
knowledge
and
skills
to
develop
an
effective
Plan.
...(
M)
any
PEs
lack
sufficient
multidisciplinary
knowledge
and
field
skills
to
develop
a
site­
specific
Plan
adequate
to
address
"all
conceivable
contingencies."
(186)

Other
environmental
professionals.

PE
can
review
work
of
others.
We
should
modify
the
regulation
to
allow
a
site
visit
by
a
person
under
the
direct
supervision
or
authority
of
the
PE
who
certifies
the
Plan.
(67,
74,
L4)
A
PE
should
not
have
to
visit
every
facility.
A
PE
who
could
not
evaluate
whether
to
visit
a
site
should
take
a
special
test
on
part
112
before
the
PE
can
certify
a
Plan.
Alternatively,
if
the
PE
does
not
conduct
a
site
visit,
he
should
state
who
provided
the
data
and
how.
(76)
Facility
environmental
professionals
should
continue
to
offer
advice
"without
being
encumbered
with
excessive,
questionably
beneficial
educational
and
certification
requirements."
A
Registered,
independent,
PE
should
certify
the
integrity
of
tanks,
piping,
containment
structures,
and
other
ancillary
process
equipment.
(162)
The
rule
"implies
that
a
Plan
or
revisions
to
a
Plan
can
be
prepared
by
nonregistered
individuals
not
associated
with
the
PE
and
that
the
PE
must
only
review
the
Plan
before
certification."
(L25)
107
Other
certifiers.
"Many
non­
engineers
have
been
and
are
employed
by
government
agencies
to
review
the
SPCC
plans
which
they
cannot
legally
certify.
This
inconsistency
is
inappropriate
and
should
be
eliminated."
"Mitchell
also
recommends
that
the
Agency
consider
accepting
certification
by
a
Registered
Environmental
Professional,
as
well
as
a
Registered
Professional
Engineer.
Either
category
of
professional
has
training
sufficient
to
evaluate
the
effectiveness
of
a
SPCC
Plan."
(24,
31,
67,
71,
74,
76,
85,
86,
115,
186)
We
should
permit
certification
by
"a
degreed
geologist/
hydrologist
with
five
years
experience,
a
degreed
engineer
with
five
years
experience,
or
a
registered
PE
."
(70)
"Facility
superintendents,
geologists,
planners,
geographers,
hydrologists,
and
people
with
many
other
qualifications
can
do
the
work
with
at
least
the
same
insight
and
of
the
same
quality
as
a
PE."
(109)

Owner/
operator
discretion
suggested.
"Because
the
facility
owner
assumes
all
liability
associated
with
the
adequacy
of
the
facility
design
and
SPCC
plan,
the
EPA
should
not
be
involved
in
specifying
who
must
certify
it."
(107)
"Questar
strongly
recommends
that
facility
owners/
operators
be
the
certifying
authority
for
the
plans
(and
amendments
thereto)
and
that
they
be
trusted
to
recognize
their
own
interests
and
employ
qualified
persons
to
prepare
the
plans.
If
EPA
rejects
that
suggestion,
we
recommend
that
PE
certification
and
review
be
eliminated
for
smaller
facilities."
(109)

PE
unnecessary.
"IPAA
would
like
to
note
that
if
all
of
the
components
of
the
SPCC
Plan
are
prescribed
by
regulations,
there
is
little
use
in
review
and
certification
by
a
Registered
Professional
Engineer."
(31,
86,
149,
176)
The
PE
certification
requirement
is
"unwarranted."
PE
certification
would
not
ensure
"adequate
protection
of
the
environment"
and
is
inconsistent
with
other
Federal
emergency
response
plan
preparation
requirements
­­
including
Resource
Conservation
Recovery
Act
(RCRA)
Contingency
planning
requirements.
(107)
The
Regional
Administrator
(RA)
"usurps"
the
need
for
a
PE,
and
we
should
only
use
the
PE
as
a
"reliable
purveyor
of
good
engineering
practice
unfiltered
by
unnecessary
regulations."
(110)
"...
Arvin
believes
that
tanks,
piping,
containment
structures,
and
other
ancillary
process
equipment
be
certified
as
to
its
integrity
by
a
registered,
independent,
professional
engineer.
However,
development
of
SPCC
plans,
etc.,
requires
a
great
deal
of
common
sense,
a
working
knowledge
of
the
facility,
knowledge
of
regulatory
requirements
and
guidelines,
etc.
None
of
these
requirements
indicate
a
need
for
a
PE."
(162)
Federal
and
most
State
hazardous
waste
management
regulations
have
no
requirement
for
a
PE
to
develop
a
contingency
plan.
(176)
PE
Plan
certification
is
unnecessary,
because
we
already
require
owners
or
operators
to
follow
good
engineering
practice.
(L27)

Small
facilities.
"PTL
agrees
that
a
registered
professional
engineer
(P.
E.)
should
review
and
certify
SPCC
plans
which
are
required
for
facilities
that
store
in
excess
of
42,000
gallons
aboveground.
We
do
not
agree
that
a
PE
is
needed
108
to
review
and
certify
a
SPCC
plan
which
has
a
storage
capacity
less
than
42,000
gallons.
Our
reasoning
is
that
facilities
that
store
less
than
42,
000
gallons
do
so
with
multiple
tanks
which
typically
consist
of
5,
000
to
10,000
gallons
in
capacity.
These
tanks
are
required
to
contain
the
Underwriters
Laboratory
Seal
of
Approval
prior
to
installation.
Moreover,
state
and
local
fire
marshal's
office
require
detailed
plans
be
submitted
to
their
office
prior
to
installation
of
these
systems.
Therefore,
it
does
not
seem
cost
effective
to
have
a
registered
engineer
develop
a
plan
to
ensure
the
integrity
of
these
systems
that
have
already
been
scrutinized
by
state
and
local
agencies."
(82,109,124,166)

Applicability
of
requirement.
We
should
insert
in
§112.3(
d)
language
"to
convey
the
thought
that
the
P.
E.
certification
pertains
only
to
compliance
with
SPCC
requirements...."
(8)

No
State
registration.
"American
Samoa
is
a
Territory
of
the
United
States
located
in
the
South
Pacific
approximately
2,
400
miles
from
the
State
of
Hawaii,
with
a
population
of
approximately
47,000.
As
a
result,
the
Government
of
American
Samoa
does
not
register
Professional
Engineers.
Therefore,
compliance
with
the
proposed
SPCC
certification
would
be
impossible."
(L21)

Certification
eligibility.
"It
appears
that
any
registered
engineer
can
certify
a
Plan.
Most
states,
if
not
all,
have
rules
of
professional
conduct
that
prohibit
licensees
from
engaging
in
work
the
engineer
is
not
competent
or
qualified
to
perform
by
reason
of
education,
training,
or
experience."
(L25)

Dates,
status,
etc.
"The
certification
attesting
to
an
examination
of
the
facility
by
the
PE
should
include
the
date(
s)
of
the
examination
and
the
topics
addressed
during
the
examination,
and
the
status
of
construction
and
other
site
preparations
as
of
the
date(
s)
of
the
examination."
(43)

Editorial
clarifications.
"The
term
`Registered'
is
not
used
in
the
Michigan
Professional
Engineer
(PE)
Act,
and
perhaps
in
other
states
as
well,
inasmuch
as
PEs
are
now
`licensed'
rather
than
registered
to
practice
engineering.
Thus
I
recommend
that
the
word
`Registered'
be
deleted
wherever
it
is
used
immediately
before
the
words
`Professional
Engineer'
in
this
regulation...."
(43)
We
should
clarify
the
rule
language
by
stating
"that
the
Engineer
shall
attest
that...
he/
she
has
examined
the
facility."
(121)

Knowledge,
information,
and
belief.
We
should
clarify
in
§112.3(
d)
that
in
certifying
a
Plan,
the
PE
makes
the
§112.3(
d)
attestations
"to
the
best
of
the
Engineer's
knowledge,
information,
and
belief."
(24)

Liability.
We
should
amend
the
rule
to
protect
a
PE
from
legal
liability
for
performance
under
§112.3(
d),
except
for
gross
negligence
or
willful
misconduct.
Because
we
do
not
require
PE
certification
for
the
facility
design,
a
PE
may
certify
a
poorly
designed
facility.
(24)
109
PE
Audit.
We
should
require
a
PE
audit
the
facility
just
before
a
facility
begins
operation
to
determine
whether
"all
elements
of
the
SPCC
Plan
are
in
place"
and
whether
"the
facility's
personnel
have
been
trained
to
deal
with
spills."
(43)

State
registration
laws.
We
should
solicit
information
from
the
National
Council
of
Examiners
for
Engineering
and
Surveying
(NCEES)
on
State
variations
in
PE
registration
laws
to
help
modify
part
112.
(26)

Time
limit
for
PE
certification.
"A
time
limit
of
less
than
three
(3)
years
should
be
placed
on
the
validity
of
the
PE's
certification.
EPA
should
require
that
the
PE
reinspect
the
premises
periodically,
preferably
annually,
to
ascertain
that
the
SPCC
Plan
continues
to
be
fully
implemented."
(43)

Existing
certifications.
Requests
"that
it
be
clarified
that
existing
SPCC
plans
are
grandfathered
from
the
PE
visitation/
recertification
requirements
until
plan
updates
are
required."
(167)

Response:
Support
for
certification
requirement.
We
appreciate
commenter
support
for
the
PE
review
and
certification
requirement.
PE
certification
of
all
facilities,
both
large
and
small,
is
necessary
because
a
discharge
as
described
in
§112.1(
b)
from
any
size
facility
may
be
harmful,
and
PE
review
and
certification
of
a
Plan
may
help
prevent
that
discharge.
Because
a
Plan
for
a
smaller
facility
is
likely
to
be
less
complicated
than
a
Plan
for
a
larger
facility,
PE
certification
costs
should
likewise
be
lower
for
a
smaller
facility.
In
our
Information
Collection
Request,
estimated
total
costs
for
a
new
facility
to
prepare
and
begin
implementation
of
a
Plan,
including
PE
certification
costs,
are
$2,
201
for
a
small
facility,
$2,
164
for
a
medium
facility,
and
$2,
540
for
a
large
facility.
This
cost
is
incurred
only
in
the
year
that
the
facility
first
becomes
subject
to
the
rule.
This
one­
time
cost
incurred
by
a
small
facility
is
less
than
1.
5
percent
of
the
average
annual
revenue
for
small
facilities
in
all
industry
categories.
The
cost
for
the
PE
certification
alone
would
represent
even
less
than
that.
As
shown
in
Chapter
5
of
the
Economic
Analysis
for
this
rulemaking,
the
average
annual
revenue
for
the
smallest
regulated
facilities
(under
the
current
rule)
ranges
from
$150,000
to
$6,833,000,
depending
on
the
industry
category.
For
example,
farms
with
annual
revenue
between
$100,000
and
$249,999
have
an
average
annual
revenue
per
farm
of
$161,430,
and
$2,201
(the
one­
time
cost
to
prepare
and
implement
a
Plan)
represents
only
1.
36
percent
of
that
annual
revenue.
Of
course,
under
the
revised
rule
many
of
these
small
facilities
will
not
be
regulated
by
the
SPCC
program
at
all.

A
PE's
certification
of
a
Plan
means
that
the
PE
is
certifying
that
the
facility's
equipment,
design,
construction,
and
maintenance
procedures
used
to
implement
the
Plan
are
in
accordance
with
good
engineering
practices.
And
this
is
important
because
good
engineering
practices
are
likely
to
prevent
discharges.
PE
certification,
to
be
effective
for
SPCC
purposes,
must
be
completed
in
accordance
with
the
law
of
the
State
in
which
the
PE
is
working.
For
example,
some
States
require
a
PE
to
apply
his
seal
to
effectuate
a
certification.
Others
do
not.
110
We
disagree
that
the
Regional
Administrator
(RA)
"usurps"
the
need
for
a
PE.
The
RA
does
not
review
or
certify
an
SPCC
Plan,
as
does
the
PE.
Therefore,
there
is
no
overlap
between
RA
and
PE
responsibilities
in
the
SPCC
Program.
The
PE
is
crucial
to
designing
a
facility­
specific
Plan
for
each
facility
that
accords
with
good
engineering
practice.
His
certification
is
necessary
to
document
that
the
Plan
was
prepared
in
accordance
with
good
engineering
practice.

We
also
disagree
that
small
facilities
need
not
have
PE
certification
for
SPCC
Plans
when
the
tanks
are
certified
by
the
Underwriters
Laboratory.
A
Plan
consists
of
more
than
a
certified
tank.
It
contains
provisions
for
secondary
containment,
integrity
testing,
and
other
measures
to
prevent
discharges.
Those
provisions
require
PE
certification
to
ensure
that
they
meet
the
requirements
of
the
rule
and
that
the
Plan
is
effective
to
prevent
discharges
Applicability
of
requirement.
We
reaffirm
that
PE
certification
requirement
in
part
112
pertains
only
to
compliance
with
SPCC
requirements.

No
State
registration.
In
response
to
the
commenter
from
Samoa,
who
noted
that
territory
does
not
register
PEs,
the
rule
would
allow
an
SPCC
facility
there
to
hire
a
PE
licensed
in
some
other
State
or
U.
S.
territory.

Dates,
status,
etc.
The
certification
must
be
dated
because
the
date
is
necessary
to
detail
compliance
with
Plan
implementation
requirements.
We
disagree
that
the
attestation
need
contain
examination
dates,
topics
addressed,
and
status
of
construction
and
other
site
preparations.
Those
items
are
more
appropriately
addressed
in
the
Plan
itself
or
for
a
log
or
appendix
to
the
Plan.

Editorial
clarifications.
Editorial
clarification.
No
editorial
change
is
necessary
because
the
owner
or
operator
is
already
required
to
make
the
Plan
available
for
on­
site
review.
See
§112.4(
d).

We
agree
that
the
correct
term
is
"licensed
Professional
Engineer,"
rather
than
"Registered
Professional
Engineer,"
and
that
is
the
term
we
use
in
the
rule.

Knowledge,
information,
and
belief.
We
agree
that
the
PE
attests
"to
the
best
of
his
knowledge,
information,
and
belief,"
but
do
not
believe
that
additional
rule
language
is
necessary
because
the
language
is
already
implicit.
We
note
that
the
attestation
requires
no
specific
formula,
merely
documentation
of
compliance
with
the
required
elements.

Liability.
We
disagree
that
we
should
amend
the
rule
to
protect
a
PE
from
legal
liability
for
performance
under
§112.3(
d),
except
for
gross
negligence
or
willful
misconduct.
PE
liability,
is
and
should
remain,
a
matter
of
State
law.

Other
environmental
professionals.
Certification
by
a
PE,
rather
than
by
another
environmental
professional
is
necessary
to
ensure
the
application
of
good
engineering
111
judgment.
Likewise,
we
disagree
that
we
should
permit
an
owner
or
operator
to
certify
the
Plan
and
technical
amendments,
or
that
we
should
eliminate
PE
Plan
review
and
certification
for
smaller
facilities.
As
described
above,
PE
certification
helps
ensure
the
application
of
good
engineering
practice.
We
agree
that
a
PE
should
be
qualified
by
education,
training,
or
experience,
and
note
that
"most
States
prohibit
licensees
from
engaging
in
work
the
engineer
is
not
competent
or
qualified
to
perform."
A
PE
must
obtain
a
Bachelor
of
Engineering
degree
from
an
accredited
engineering
program,
pass
two
comprehensive
national
examinations,
and
demonstrate
an
acceptable
level
(usually
four
additional
years)
of
engineering
experience.
A
licensed
engineer
is
also
required
to
practice
engineering
solely
within
his
areas
of
competence
and
to
protect
the
public
health,
safety,
and
welfare.
We
also
believe
that
prescribing
the
credentials
for
a
PE
should
be
a
matter
of
State,
not
Federal
law.
Licensing
criteria
may
differ
somewhat
among
the
States.
All
licensed
PEs,
no
matter
who
their
employer,
are
required
by
State
laws
and
codes
of
ethics
to
discharge
their
engineering
responsibilities
accurately
and
honestly.
Furthermore,
State
governments
have
and
do
exercise
the
authority
to
discipline
licensed
PEs
who
fail
to
comply
with
State
laws
and
requirements.
Other
environmental
professionals
may
not
have
similar
expertise
nor
be
held
to
similar
standards
as
the
licensed
PE.

PE
Audit.
We
also
disagree
that
we
should
require
a
PE
audit
the
facility
just
before
a
facility
begins
operation
to
determine
whether
"all
elements
of
the
SPCC
Plan
are
in
place"
and
whether
"the
facility's
personnel
have
been
trained
to
deal
with
spills."
Those
tasks
are
the
responsibility
of
the
owner
or
operator,
not
the
PE.
PE
certification
does
not
relieve
an
owner
or
operator
of
a
facility
of
his
duty
to
prepare
and
fully
implement
the
Plan
in
accordance
with
part
112
requirements.
40
CFR
112.3(
d)(
2).

State
registration
laws.
We
disagree
that
we
should
solicit
information
from
the
National
Council
of
Examiners
for
Engineering
and
Surveying
(NCEES)
on
State
variations
in
PE
registration
laws
to
help
modify
part
112
because
such
information
is
not
necessary
to
the
implementation
of
the
SPCC
program.
PE
registration,
is
and
should
remain,
a
matter
of
State
law.
PE
certification,
to
be
effective
for
SPCC
purposes,
must
be
completed
in
accordance
with
the
law
of
the
State
in
which
the
PE
is
working.
For
example,
some
States
require
a
PE
to
apply
his
seal
to
effectuate
a
certification.
Others
do
not.

Time
limit
for
PE
certification.
We
disagree
that
there
should
be
a
time
limit
on
PE
certification
because
the
rule
ensures
that
the
PE
reviews
the
Plan
at
appropriate
times.
We
also
disagree
that
we
should
require
periodic
PE
reinspection
of
a
facility.
Thus,
current
PE
certifications
remain
valid.
But
new
certifications
after
the
effective
date
of
this
rule
must
include
the
required
attestations.
If
you
are
an
owner
or
operator
you
must
review
your
Plan
at
least
every
five
years
(under
revisions
made
in
today's
rule),
and
amend
it
if
new
technology
is
warranted.
Also,
you
must
amend
your
Plan
to
conform
with
any
applicable
rule
requirements,
or
at
any
time
you
make
any
change
in
facility
design,
construction,
operation,
or
maintenance
that
materially
affects
its
potential
for
a
discharge
as
described
in
§112.1(
b).
All
material
amendments
require
PE
certification.
Therefore,
because
a
Plan
will
likely
require
one
or
more
amendments
112
requiring
PE
review
and
certification,
a
time
limit
on
PE
certifications
is
unnecessary.
See
§112.5(
c).
113
VI
­
D:
Whether
the
certifying
PE
may
be
a
facility
employee
or
have
any
direct
financial
tie
to
the
facility
­
§112.3(
d)

Background:
In
the
1991
preamble,
we
requested
comments
on
whether
the
certifying
PE
should
be
an
employee
of
the
owner
or
operator,
or
have
"any
other
direct
financial
interest
in
the
facility."
The
rationale
for
this
proposal
was
to
avoid
conflicts
of
interest
or
the
appearance
of
a
conflict
of
interest
between
a
facility
owner
or
operator
and
the
PE.

Comments:
Support
for
independent
PE.

Conflict
of
interest.
"I
believe
that
specially
with
SPCC
planning
and
implementation
is
valuable
for
the
certifying
P.
E.
not
to
be
an
employee
of
the
company
so
that
he
can
be
more
objective
and
thus
help
in
arriving
at
decisions
which
will
help
assure
that
the
objectives
of
this
regulation
are
achieved."
(21,
121,
142,
168,
and
L8)
"On
the
other
hand
the
employee
engineer
may
be
reticent
because
of
job
position
or
other
reasons
about
recommending
major
facility
modifications,
if
these
are
determined
to
be
necessary
during
development
or
review
of
a
plan."
(16,
21,
121,
142,
158,
L8)

More
economical.
"Also,
many
companies
are
now
finding
that
it
is
more
economical
to
engage
a
SPCC
trained
and
competent
P.
E.
who
is
not
an
employee,
rather
than
train
an
employee
in
the
requirements
specified
by
the
SPCC
regulations."
(21)

More
objectivity.
"I
believe
that
specially
with
SPCC
planning
and
implementation
it
is
valuable
for
the
certifying
P.
E.
not
to
be
an
employee
of
the
company
so
that
he
can
be
more
objective
and
thus
help
in
arriving
at
decisions
which
will
help
assure
that
the
objectives
of
this
regulation
are
achieved.
The
private
practice
P.
E.
can,
without
fear
of
losing
his
pension,
benefits,
job,
etc.,
be
an
objective
and
cooperating
individual
who
assists
the
owner
and
the
regulating
agencies
and
thereby
satisfies
his
duties
more
comfortably
of
serving
the
public."
(21,
168,
L8)

Opposition
to
independent
PE
requirement.

Ethics.
"To
suppose
that
a
facility
employee
would
break
the
law
and
jeopardize
his
license
to
practice
his
profession
and
do
it
more
willingly
than
an
`independent'
engineer
has
no
basis
in
fact
and
is
perhaps
diametrically
opposed
to
real
world
realities."
"Regarding
financial
interest,
an
independent
engineer
may
have
just
as
great,
if
not
more,
financial
interest
in
accommodating
the
facility
operator/
owner."
(5,
6,
9,
14,
15,
16,
23,
24,
31,
34,
35,
36,
39,
40,
41,
51,
52,
54,
56,
58,
59,
67,
71,
72,
74,
80,
88,
90,
92,
96,
98,
103,
105,
110,
113,
114,
115,
117,
125,
126,
131,
133,
135,
136,
141,
143,
146,
155,
161,
165,
167,
170,
173,
175,
180,
181,
183,
184,
189,
190,
L4,
L9,
L15,
L19,
L20,
L25,
L30,
L31,
L32)
114
Enforcement
mechanisms.

EPA
enforcement.
"EPA
can
also
take
enforcement
action
for
false
certifications."
(35)
"EPA
should
adopt
an
enforcement
policy
for
taking
action
against
the
licence
of
a
PE
if
the
performance
of
the
PE
is
not
consistent
with
professional
standards,
or
is
negatively
biased
by
the
PE's
relationship
to
an
operator."
(52)
"Abuses
of
the
certification
function
should
be
subject
to
administrative
fines
just
as
are
other
violations
of
the
rules.
This
is
a
better
method
of
ensuring
proper
certification,
rather
than
trying
to
limit
the
use
of
all
employee
PEs."
(71,
96)

State
law.
"State
laws
and
regulations
establish
adequate
complaint
procedures
and
penalties
for
violations
of
the
standard
of
practice
to
which
Professional
Engineers
are
held."
(5)
"EPA
should
not
legislate
in
areas
of
state
concern,
such
as
requirements
that
constitute
appropriate
engineering
practices."
(35)
"Professional
engineers
are
registered
by
state
engineering
boards,
which
are
responsible
for
overseeing
their
ethics
and
technical
qualifications.
As
a
result,
all
professional
engineers
are
expected
to
uphold
the
same
professional
standards,
regardless
of
the
entity
who
employs
them
or
any
other
direct
financial
interest
in
the
facility."
(146)

Familiarity
with
facility.
"Depriving
the
owner
of
the
use
of
his
own
engineer
would
in
many
instances
exclude
the
most
qualified
person
from
producing
the
plan.
The
result
may
well
be
that
the
average
new
plan
will
be
inferior
to
those
already
in
existence."
(5,
6,
25,
31,
38,
47,
53,
59,
62,
71,
72,
74,
75,
77,
78,
80,
86,
88,
89,
90,
92,
98,
101,
105,
112,
116,
124,
133,
135,
136,
137,
141,
143,
145,
146,
153,
155,
160,
161,
164,
165,
167,
173,
180,
181,
183,
191,
L3,
L7,
L14,
L15,
L29)

Financial
burden.
"The
requirement
of
hiring
an
independent
engineer
would
also
place
a
tremendous
financial
burden
on
facility
owners.
...
A
further
substantial
source
of
financial
burden
would
be
in
revising
a
plan
previously
written
by
an
independent
engineer."
(6,
9,
10,
27,
28,
34,
35,
38,
41,
42,
47,
48,
54,
62,
68,
71,
79,
90,
91,
93,
98,
103,
105,
110,
112,
115,
125,
134,
136,
137,
139,
141,
146,
153,
155,
160,
167,
173,
175,
181,
182,
183,
188,
190,
191,
192,
L2,
L3,
L14,
L18,
L20,
L29,
L31)

Insurance.
"We
are
also
concerned
whether
an
independent
PE
could
really
afford
the
insurance
to
certify
his
work."
(71)

Financial
interest,
inside
and
outside
PEs.

Outside.
"Merely
by
contracting
with
the
facility
to
review
and
certify
SPCC
plans,
the
PE
is
engaging
a
financial
interest
in
the
operation."
"The
premise
that
an
employee
of
a
facility
has
a
financial
interest
in
the
company,
but
that
a
115
consultant
PE
under
contract
to
the
facility
does
not,
is
incorrect.
A
consultant
PE
also
receives
payment
from
the
facility
for
his/
her
work.
The
difference
between
the
employee
PE
and
the
consultant
PE
is
simply
that
a
consultant's
services
are
over
once
the
service
has
been
provided.
If
a
consultant
PE
does
not
render
satisfactory
service,
he/
she
may
not
be
retained
in
the
future."
(6,
27,
47,
52,
76,
77,
95,
102,
116,
125,
136,
164,
165,
181,
187,
189,
L14,
L15)

Inside.
"We
believe,
moreover,
that
the
`independent'
engineer
proposal
ignores
the
fact
that
`independent'
engineers
may
also
have
conflicting
financial
interests
that
could
lead
to
bias.
Retained
experts,
after
all,
have
a
strong
interest
in
satisfying
clients
in
the
hope
of
renewed
retention
on
future
company
projects.
A
tenured
company
engineer
may
have
greater
job
security
and
face
less
risk
of
dismissal
for
professional
independence
than
a
retained
expert
who
has
no
assurance
of
retention
on
future
company
projects
requiring
engineering
services."
(125)

Compromise
position.
"Perhaps
the
compromise
here
is
that
the
PE
who
certifies
the
SPCC
Plan
be
required
to
disclose
in
the
SPCC
Plan
certification
his
or
her
relationship
to
the
facility
owner,
the
facility
improvement
owner,
and
the
facility
landowner."
(47)

Direct
financial
interest.
We
should
clarify
the
definition
of
the
phrase
"other
direct
financial
interest."
(87)

Response:
We
agree
that
a
proposal
to
restrict
certification
by
a
PE
employed
by
a
facility
or
having
a
financial
interest
in
it
would
limit
the
availability
of
PEs,
possibly
leading
to
delays
in
Plan
certification.
Therefore,
we
will
not
adopt
it.
Nor
do
we
favor
the
proposal
to
require
the
PE
to
disclose
his
relationship
to
the
facility
owner,
the
facility
improvements
owner,
or
the
facility
landowner.
Such
disclosure
would
add
no
environmental
protection
to
the
SPCC
certification
process.
We
agree
that
there
are
mechanisms
in
place
to
enforce
ethical
conduct
by
PEs.
State
licensing
boards
expect
PEs
to
uphold
professional
standards
and
can
discipline
PEs
for
unprofessional
conduct.
State
administrative
action
to
correct
abuses
may
be
an
appropriate
approach.
We
believe
that
most
PEs,
whether
independent
or
employees
of
a
facility,
being
professionals,
will
uphold
the
integrity
of
their
profession
and
only
certify
Plans
that
meet
regulatory
requirements.
We
also
agree
that
an
in­
house
PE
may
be
the
person
most
familiar
with
the
facility.
EPA
believes
that
a
restriction
of
in­
house
PE
certification
might
place
an
undue
and
unnecessary
financial
burden
on
owners
or
operators
of
facilities
by
forcing
them
to
hire
an
outside
engineer.

Direct
financial
interest.
Because
we
have
not
adopted
a
requirement
for
an
independent
PE,
it
is
not
necessary
to
discuss
what
is
a
"direct
financial
interest."
116
VI
­
E:
PEs
­
State
registration
­
§112.3(
d)

Background:
In
the
preamble
to
the
1991
proposal,
we
requested
comments
on
the
advantages
and
disadvantages
of
requiring
a
certifying
Professional
Engineer
(PE)
to
be
licensed
in
the
State
where
the
facility
is
located.

Comments:
Support
for
proposal.

Familiarity
with
local
rules,
conditions,
etc.
"Familiarity
with
the
state
and
local
requirements
related
to
the
facilities
as
well
as
the
state
itself
are
essential
for
viable
SPCC
plans.
This
is
particularly
true
in
Alaska
when
considering
our
unique
geography
and
climate."
(43,
52,
54,
77,
111,
134,
142,
143,
153,
158,
159,
185)

Implementation.
If
a
PE
prepares
a
facility
Plan
in
a
State
where
the
PE
is
not
registered,
another
PE
who
is
registered
in
the
State
should
certify
the
Plan.
(159,
L25)

Diligent
efforts.
While
the
certifying
PE
should
be
registered
in
the
State
where
the
facility
is
located,
the
owner
or
operator
should
be
able
to
use
a
PE
registered
in
another
State
if
after
the
diligent
efforts,
the
owner
or
operator
cannot
find
a
PE
registered
in
the
State
to
certify
the
Plan.
(51)

State
licensing
boards.
"State
laws
and
regulations
establish
adequate
complaint
procedures
and
penalties
for
violations
of
the
standard
of
practice
to
which
Professional
Engineers
are
held."
(4,
5,
14,
23,
40,
42,
43,
71,
72,
76,
80,
86,
121,
128,
143,
154,
173,
190,
L4,
L17)

Opposition
to
State
licensing
requirement.

Cost.
"Additional
requirements
for
same­
state
registration
or
financial
independence
of
the
Engineer
would
place
a
greater
burden
on
the
regulated
community
without
providing
greater
benefits
to
the
SPCC
program."
(10,
15,
27,
31,
34,
48,
57,
59,
65,
68,
78,
79,
86,
87,
103,
109,
112,
116,
125,
137,
150,
160,
175,
182,
191,
L3,
L30)

Familiarity
with
State
and
local
requirements.
"Furthermore,
being
certified
in
a
particular
state
does
not
necessarily
mean
that
the
engineer
has
significant
professional
experience
in
the
state.
Because
many
of
today's
professionals
are
mobile
and
prone
to
transfers,
it
is
not
uncommon
for
a
professional
engineer
to
spend
most
of
his
working
career
in
states
other
than
the
one
where
he
received
his
certification.
Also,
because
of
reciprocal
agreements
between
certification
boards
in
different
states,
it
is
possible
to
obtain
certification
in
a
one
sate
by
virtue
of
having
been
certified
in
a
different
state.
Clearly,
certification
in
a
particular
state
does
not
automatically
mean
that
the
engineer
is
more
familiar
with
that
state's
codes
and
regulations
than
any
other
professional
engineer."
117
(9,
27,
31,
34,
36,
39,
42,
48,
54,
56,
57,
59,
62,
66,
67,
72,
78,
86,
87,
89,
90,
95,
101,
102,
103,
105,
109,
112,
114,
124,
125,
128,
130,
133,
136,
137,
143,
145,
150,
152,
160,
165,
167,
170,
173,
188,
190,
191,
L29,
L30,
L32)

No
environmental
benefit.
"First,
requiring
that
the
professional
engineer
that
certifies
a
given
plan
be
registered
in
the
same
state
as
where
the
facility
is
located
provides
no
additional
pollution
prevention.
The
exams
that
are
administered
as
part
of
the
certification
process
for
a
professional
engineer
deal
with
engineering
concepts.
The
vast
majority
of
these
exams
are
standardized
and
do
not
address
state
specific
issues,
such
as
codes
and
regulations.
Therefore,
certification
within
a
given
state
does
not
necessarily
mean
that
the
engineer
is
more
familiar
with
the
codes
and
laws
of
that
particular
state."
(71,
95,
102,
114,
145,
167,
170,
173,
175,
182,
L29)

State
licensing
boards.
"A
State
licensing
board
will
address
the
actions
of
an
engineer
licensed
by
that
board
regardless
of
the
engineer's
location
when
he
applies
his
seal."
(75,
79,
80,
95,
102,
110,
113,
136,
155,
175,
182,
184,
L7,
L9,
L32)

Would
reduce
the
pool
of
available
PEs.
"Because
of
the
antiquated
nonreciprocal
licensing
laws
which
exist
among
most
of
the
states,
it
is
practically
impossible
(and
certainly
not
cost
effective)
for
a
professional
engineer
to
be
licensed
in
every
state."
(15)

Response:
We
agree
with
commenters
that
it
is
unnecessary
that
the
PE
be
registered
or
licensed
in
the
State
in
which
the
facility
is
located
because
any
abuses
will
be
corrected
by
the
licensing
jurisdiction.
We
also
agree
that
such
a
requirement
might
unnecessarily
reduce
the
availability
of
PEs
and
increase
the
cost
of
certification
without
any
tangible
benefits.
The
professional
liability
of
a
PE
would
likely
be
unaffected
by
the
place
of
his
registration.
When
State
law
precludes
a
PE
from
applying
his
seal
if
he
is
not
licensed
in
that
State,
the
question
of
State
registration
becomes
moot.
However,
that
is
not
the
case
in
every
State.

We
also
disagree
that
if
a
PE
is
not
licensed
in
the
State,
he
will
be
unfamiliar
with
State
and
local
requirements
for
the
facility.
Any
PE
may
become
familiar
with
both
Federal
and
State
and
local
requirements
for
a
facility.
Therefore,
to
require
that
the
PE
be
registered
in
the
State
in
which
the
facility
is
located
would
impose
unnecessary
financial
burdens
on
the
facility
and
would
challenge
the
integrity
of
the
PE.
Such
a
requirement
would
also
reduce
the
pool
of
PEs
available
for
facilities.

VI
­
F:
PEs
­
Site
visits
­
§112.3(
d)

Background:
Under
§112.3(
d)
of
the
current
rule,
a
PE
must
attest
that
he
has
"examined
the
facility"
before
certifying
that
facility's
SPCC
Plan.
In
1991,
we
proposed
to
clarify
that
the
PE
must
examine
the
facility
in
person.
118
Comments:
Support
for
proposal.
"The
language
changes
in
the
proposed
regulation
clarifies
the
requirement
that
the
certifying
engineer
must
physically
visit
the
facility.
Ohio
EPA
agrees
with
this
change."
(15,
27,
39,
52,
74,
75,
80,
95,
102,
121,
136,
141,
158,
161,
168,
175,
L29)

Good
engineering
practice.
"Prior
to
preparing
or
re­
certifying
an
SPCC
plan,
it
is
agreed
that
a
site
visit
is
absolutely
necessary.
The
certifying
PE
is
able
to
review
all
aspects
of
the
plan
with
local
management
and
leave
with
reasonable
assurance
that
the
facility
would
be
able
to
prevent
and/
or
respond
to
any
spill
event.
Spill
clean­
up
and
retention
equipment
should
be
inspected
as
well
as
response
personnel
training."
(15,
39,
L29)

Opposition
to
proposal.
(9,
24,
28,
35,
36,
58,
65,
67,
71,
76,
78,
82,
87,
101,
113,
115,
116,
134,
145,
165,
183,
192,
L4,
L15,
L30)

Available
documentation.
"A
PE
is
expected
to
have
the
proficiency
to
comprehend
the
requirements
of
the
rule
and
assess
the
completeness
of
the
plan
for
the
facility
based
on
available
information
and
technical
backup."
(28,
87,
101,
115,
116,
165)
A
PE
site
visit
will
not
materially
improve
the
Plan.
The
PE
can
use
topographic
maps,
photographs,
and
other
methods
to
make
an
informed
decision.
(87)
A
site
visit
"may
not
provide
any
better
information
than
if
the
facility
was
required
to
provide
a
professional
engineer
geographical
and
geological
information
that
depicts
land
and
water
within
one­
quarter
mile
of
the
facility
boundaries."
(115)
A
visit
is
unnecessary
at
small
facilities
with
adequate
drawings,
photos,
or
other
documentation.
(116)

Cost.
"Site
visits
to
physically
examine
the
facility
would
involve
additional
direct
cost
and
duplication
of
efforts
with
possibly
no
benefits
on
the
overall
effectiveness
of
the
plant."
(9,
28,
36,
65,
82,
101,
145,
165,
L30)
The
site
visit
cost
is
unnecessary
if
the
PE
is
"familiar"
with
the
facility.
(36)
A
site
visit
imposes
substantial
additional
costs
since
many
entities
use
vaulted
aboveground
storage
tanks
at
remote
locations
to
support
transmitter
sites
and
backup
generator
sites.
(65)
"Many
sites
scattered
throughout
Appalachia
are
remote,
access
is
difficult,
and
travel
time
expensive.
This
requirement
places
an
enormous
burden
in
terms
of
increasing
the
cost
for
the
SPCC
plan.
The
engineer
should
be
able
to
understand
the
adequacy
of
the
construction
in
the
containment
plan
from
the
documents
provided.
The
Registered
Professional
Engineer
can
request
additional
documentation
if
the
engineer
deems
it
so
necessary."
(101,
115,
145,
165)

Electrical
equipment.
Due
to
the
large
number
of
station,
"it
would
be
impractical
for
the
certifying
PE
to
visit
and
inspect
each
site
when
preparing
SPCC
Plans."
(134,
183)

Multiple
sites.
It
is
difficult
for
the
certifying
PE
to
visit
multiple
facilities.
(9,
39,
71,
76,
78,
101,
115,
134,
145)
"Where
a
number
of
facilities
at
distant
119
locations
with
similar
operations
or
belonging
to
the
same
owner
are
involved,
the
extra
effort
and
costs
for
physical
examination
of
each
site
may
not
be
justifiable.
"
(9)

Similar
facilities.
A
company
with
multiple
facilities
should
send
PEs
from
sister
plants
or
corporate
headquarters
to
assist
in
the
review.
(39)
"We
also
question
whether
a
PE
should
visit
each
and
every
site.
Pennzoil
builds
its
new
company­
owned
lube
facilities
to
uniform
corporate
plans
and
makes
the
plans
available
to
both
franchised
or
other
Pennzoil
`featuring'
quick
lube
operations.
A
PE
should
not
be
required
to
visit
each
site
if
he
knows
that
the
facility
has
been
built
to
these
specifications.
Rather,
an
exemption
should
be
granted
for
similarly
situated
and
operated
facilities,
provided
that
the
PE
is
familiar
with
the
basic
plan
(i.
e.,
the
corporate
quick
lube
facility
design
or
the
tank
battery
design."
(71,
78,
145)

NSPE
opinion
­
ethics.
A
recent
opinion
of
the
National
Society
of
Professional
Engineers'
Board
of
Ethical
Review
on
a
hypothetical
case
involving
SPCC
Plan
certification
concluded
that
it
was
appropriate
for
the
PE
to
make
a
certification
without
having
visited
a
given
facility.
(24)

Off­
site
engineers.
Off­
site
engineers
often
design
a
facility
or
structure
without
ever
visiting
the
site.
(192)

Plan
information
veracity.
The
burden
of
proving
the
veracity
of
SPCC
Plan
information
should
be
on
the
facility
owner
or
operator.
(9)

Small
facilities.
We
should
not
require
a
site
visit
for
small
entities.
(82,
116,
134,
183)
"...(
D)
ifferential
requirements
based
on
facility
size
may
be
valid."
We
should
change
the
rule
to
excuse
"small"
facility
site
visits
when
there
is
"a
determination
that
sufficient
documentation
of
site
characteristics
is
available
for
plan
certification."
(183)

Temporary
storage.
"The
requirement
that
a
professional
engineer
examine
each
storage
`facility'
is
similarly
impractical
for
temporary
(often
mobile)
storage."
(60)

Response:
In
general.
EPA
agrees
that
the
rule
should
not
necessarily
require
a
site
visit
by
a
certifying
PE,
but
we
believe
that
a
site
visit
should
occur
before
the
PE
certifies
the
Plan.
We
have
modified
proposed
§112.3(
d)(
ii)
to
reflect
this
position.
The
PE's
agent
may
perform
the
visit.
We
agree
that
customary
engineering
practice
allows
someone
under
the
PE's
employ
such
as
an
engineering
technician,
technologist,
graduate
engineer,
or
other
qualified
person
to
prepare
preliminary
reports,
studies,
and
evaluations
after
visiting
the
site.
Then
the
PE
could
legitimately
certify
the
Plan.
Nevertheless,
in
all
cases
the
PE
must
ensure
that
his
certification
represents
an
exercise
of
good
engineering
judgment.
If
that
requires
a
personal
site
visit,
the
PE
must
visit
the
facility
himself
before
certifying
the
Plan.
120
Particular
cases.
EPA
agrees
that
a
PE
site
visit
requirement
might
be
impractical
at
electrical
substations,
due
to
their
large
number.
However,
the
PE
need
not
go.
One
of
his
agents
may
go,
and
he
may
review
the
agent's
work.
We
disagree
with
commenters
who
believe
that
a
site
visit
is
unnecessary
at
small
facilities
and
temporary
storage
facilities.
Site
visits
are
necessary
for
those
facilities
to
ensure
Plan
adequacy
and
to
prevent
discharges.

EPA
has
interpreted
the
current
rule
language
to
contain
a
requirement
that
the
PE
examine
the
facility.
Because
of
the
uncertainty
concerning
the
nature
of
this
requirement,
however,
we
will
not
require
documentation
of
a
site
visit
by
a
PE
or
his
agent
until
after
the
effective
date
of
this
rule.
We
disagree
that
the
rule
should
only
require
that
the
PE
be
familiar
with
the
operation
and
design
of
the
type
of
facility.
We
also
disagree
that
merely
because
the
PE
has
visited
and
examined
one
or
more
facilities
of
a
particular
type
that
no
site
visit
is
necessary.
A
facility
may
have
individual
characteristics
that
differ
from
those
of
its
type
in
general,
and
a
site
visit
by
a
PE
or
agent
may
be
necessary
to
detect
those
characteristics
and
accommodate
them
in
the
Plan.
Such
individual
characteristics
include
geographic
conditions,
possible
flow
paths,
facility
design
and
construction,
type
of
containers,
product
stored,
particular
equipment,
and
the
integrity
of
containment
at
the
facility.
Therefore,
even
if
a
PE
has
inspected
many
facilities
of
a
particular
type,
that
fact
does
not
eliminate
the
need
for
a
site
visit
at
each
facility.
After
the
site
visit
by
the
PE
or
his
agent,
the
PE
will
have
to
devise
appropriate
inspection
and
testing
standards
based
on
the
facility's
unique
characteristics.

Cost.
We
have
imposed
no
additional
burden
on
an
owner
or
operator
by
clarifying
the
rule
language.
To
mitigate
costs,
we
allow
the
PE
to
send
an
agent
to
a
site
to
conduct
the
site
visit.
That
agent
might
be,
for
example,
an
engineering
technician,
technologist,
graduate
engineer,
or
other
qualified
person
to
prepare
preliminary
reports,
studies,
and
evaluations
after
visiting
the
site.
After
review
of
the
agent's
work,
the
PE
could
legitimately
certify
the
Plan.

Editorial
clarifications.
"Registered
Professional
Engineer"
becomes
"licensed
Professional
Engineer."
The
first
sentence
of
the
paragraph
was
proposed
as,
"No
SPCC
Plan
shall
be
effective
to
satisfy
the
requirements
of
this
part
unless
it
has
been
reviewed
by
a
Registered
Professional
Engineer."
We
revised
it
to
read,
"A
licensed
Professional
Engineer
must
review
and
certify
a
Plan
for
it
to
be
effective
to
satisfy
the
requirements
of
this
part."
This
revision
is
due
to
the
fact
that
PEs
are
licensed
by
States.

Inspection
requirements.
We
agree
that
inspection
of
equipment
is
essential
to
Plan
certification;
training
of
personnel
for
response
purposes
is
not
required
by
the
SPCC
rule
and
the
PE
does
not
certify
such
training
in
his
attestation.

Plan
information
veracity.
We
agree.
The
owner
or
operator
has
a
duty
under
§112.
3(
d)
to
prepare
and
fully
implement
the
Plan.
Therefore,
the
facility
owner
or
operator
ultimately
is
responsible
for
providing
the
PE
with
accurate
information.
121
Small
facilities.
We
believe
that
a
site
visit
is
necessary
for
every
facility,
regardless
of
size,
to
prepare
a
Plan
which
will
prevent
a
discharge
as
described
in
§112.1(
b).
122
VI
­
G:
PE
Plan
Certification
­
completion
of
testing
procedures
­
§112.3(
d)

Comments:
Support
for
proposal.
"Proposed
§112.3(
d)
adds
responsibilities
to
the
Professional
Engineer
(PE)
in
the
preparation
of
SPCC
Plans.
The
PE
must
certify
`that
required
testing
has
been
completed.
'
Alyeska
supports
this
requirement."
(77)

Inspection.
"I
think
it
would
be
better
for
the
engineer
to
enumerate
all
the
inspections
and
tests
that
have
been
completed,
plus
those
that
should
be
completed
before
the
facility
commences
operations
and
those
that
should
be
undertaken
periodically
after
it
commences
operations."
(43)

Tests
required.
"`
Required
testing'
is
not
explained
or
defined
and
therefore
unclear.
East
Ohio
Gas
recommends
`required
inspection'."
(70)

PE
presence.
We
should
clarify
whether
the
PE
must
be
present
during
testing.
(58)

Test
completion.
"Unfortunately
much
of
the
testing
required
under
an
SPCC
Plan
need
not
be
performed
before
the
Plan
must
be
certified.
Thus,
the
Engineer
cannot
attest
to
that
Plan
until
all
testing
has
been
completed,
which
can
take
up
to
a
year
to
complete.
Instead
of
attesting
to
the
`completion
of
required
testing',
we
suggest
that
the
engineer
be
allowed
to
attest
to
the
presence
of
those
written
procedures,
which
require
testing.
By
so
doing,
an
engineer
can
certify
the
Plan
before
a
facility
begins
operations."
(33,
102)
"This
would
appear
to
be
an
implementation
activity,
and
should
be
the
responsibility
of
the
operator,
not
the
engineer.
In
addition,
unless
the
engineer
is
actually
present
at
or
performs
the
testing,
his/
her
ability
to
`attest'
to
such
would
be
limited
to
a
review
of
the
results.
Because
these
test
results
are
to
be
maintained
at
the
facility
in
any
event,
this
requirement
would
make
such
an
attestment
redundant."
(76,
121,146)

Response:
Support
for
proposal.
We
appreciate
commenter
support.

Testing.
EPA
agrees
that
the
PE
is
not
responsible
for
certifying
that
all
required
testing
has
been
completed.
Rather,
such
responsibility
belongs
to
the
owner
or
operator
of
the
facility.
Testing
may
be
ongoing
long
after
the
Plan
is
certified.
The
PE
is
responsible
for
certifying
that
the
Plan
is
adequate
and
meets
all
regulatory
requirements,
including
enumeration
of
all
tests
that
have
been
completed,
plus
those
that
should
be
completed
before
the
facility
commences
operations
and
those
that
should
be
undertaken
periodically
after
it
commences
operations.
Therefore,
we
are
changing
the
proposed
requirement
to
a
requirement
in
which
the
PE
attests
that
the
procedures
for
required
inspections
and
testing
have
been
established,
and
the
Plan
is
adequate
for
the
facility.
See
the
discussion
of
§112.
3(
d)
in
today's
preamble
and
immediately
above
in
this
document.
123
VI
­
H:
Plan
location
at
the
facility
­
§112.3(
e)

Background:
Under
§112.3(
e)
of
the
current
rule,
an
owner
or
operator
must
maintain
the
Plan
at
the
facility
if
it
is
attended
at
least
eight
hours
a
day,
or
at
the
nearest
field
office
if
the
facility
is
attended
less
than
eight
hours
a
day.
In
1991,
we
proposed
changing
the
eight­
hour
threshold
to
four
hours
to
ensure
that
a
facility
operating
one
shift
per
day
has
a
Plan
on
site.

Comments:
Support
for
proposal.
"We
strongly
agree
with
the
proposed
change
to
four
hours,
that
a
facility
must
be
manned
in
order
for
a
copy
of
the
SPCC
plan
to
be
maintained
at
the
facility.
This
will
ensure
that
facilities
that
operate
only
one
shift
per
day
will
have
an
SPCC
plan
on
site.
We
have
frequently
been
told
by
facilities
that
they
will
have
to
send
us
a
copy
of
their
plan
from
company
headquarters
when
one
is
requested
during
a
site
inspection
or
spill
response."
(27,
42,101,
L11).

"Without
advance
notice."
Would
add
the
words
"without
advance
notice"
to
end
of
proposed
§112.3(
d)(
2).
"This
change
will
emphasize
the
need
to
have
the
SPCC
Plan
fully
implemented
at
all
times,
not
just
when
there
is
notice
of
an
impending
inspection."
(43)

Opposition
to
proposal.

Less
than
four
hours;
inconsistent
requirements.
"Under
40
CFR
111.
3(
e)(
1),
the
SPCC
Plan
may
maintain
a
copy
of
the
Plan
at
the
nearest
field
office
if
the
facility
is
attended
less
than
four
hours
a
day.
Under
40
CFR
112.3(
e)(
2),
however,
the
Plan
must
also
be
available
for
on­
site
review
during
normal
working
hours.
These
are
mutually
inconsistent
when
applied
to
a
facility
operating
less
than
four
hours
per
day.
...
It
is
apparent
from
the
preamble,
however,
that
EPA
expects
facilities
to
have
their
Plan
available
at
all
times
at
the
facility.
Thus,
we
see
no
rationale
for
having
the
Plan
maintained
at
the
nearest
field
office
instead
of
at
the
facility
itself.
We
would
suggest,
therefore,
that
the
Plan
be
maintained
only
at
the
facility
and
not
the
nearest
field
office."
(33).

Editorial
clarification.
Suggests
using
the
following
text
to
clarify
§112.3(
e).
"Owners
or
operators
of
facilities
subject
to
this
part
must
maintain
a
copy
of
the
SPCC
Plan
for
the
facility,
prepared
pursuant
to
section
112.3(
a),
(b),
(c),
at
the
facility
if
the
facility
is
normally
attended
at
least
four
hours
a
day.
If
the
facility
is
attended
less
than
four
hours
a
day,
a
copy
of
the
plan
must
be
maintained
at
the
field
office
nearest
to
the
facility.
The
owner
or
operator
shall
make
the
plan
available
to
the
Regional
Administrator
upon
demand
for
on­
site
inspection
during
normal
working
hours."
(121)

Location
of
Plan
information.
A
"weather­
protected
(laminated)"
copy
of
the
facility
diagram
and
response
actions
should
always
be
displayed
in
an
obvious
location
near
the
main
entry
of
the
facility,
and
at
"appropriate
control
centers."
(76)
124
"Normal
working
hours."
It
is
unclear
whether
"normal
working
hours"
in
proposed
§112.3(
e)(
2)
refers
to
EPA
working
hours
or
the
facility's
working
hours.
(95,
101,
102)
If
"normal
working
hours"
are
our
hours,
then
facilities
staffed
fewer
hours
than
we
are
cannot
meet
this
requirement.
If
"normal
working
hours"
are
the
facility
hours,
then
there
is
no
problem
with
the
requirement.
(95,
102)

Response
personnel.
We
should
modify
the
proposal
to
require
keeping
the
Plan
at
the
nearest
office
with
operational
responsibility
for
the
facility
or
at
the
emergency
response
center
to
ensure
that
response
personnel
have
access
to
the
Plan.
(125)

State
and
local
agencies.
"LEPCs
and
SERCs
would
find
it
helpful
to
be
aware
of
the
availability
of
SPCC
Plans
and
may
wish
to
use
them
to
augment
their
local
and
State
response
plans."
(L11)

Response:
Support
for
proposal.
We
appreciate
commenter
support.

Nearest
field
office,
normal
working
hours.
The
term
"nearest
field
office"
in
paragraph
(e)(
1)
means
the
office
with
operational
responsibility
for
the
facility,
or
the
emergency
response
center
for
the
facility,
because
those
locations
ensure
accessibility
for
personnel
who
need
to
respond
in
case
of
a
discharge.
The
term
"normal
working
hours"
in
paragraph
(e)(
2)
refers
to
the
working
hours
of
the
facility
or
the
field
office,
not
EPA.

Location
of
Plan
information.
While
an
owner
or
operator
may
place
a
laminated
copy
of
the
Plan
at
a
conspicuous
place
at
the
facility,
there
is
no
Federal
requirement
to
do
so.
We
do
not
require
the
owner
or
operator
to
keep
the
Plan
in
any
particular
place
at
the
facility,
merely
"at
the
facility"
when
it
is
manned
at
least
four
hours
a
day.

Plan
availability.
Today
we
have
finalized
the
1991
proposal
that
the
Plan
must
be
available
at
the
facility
if
it
is
normally
attended
at
least
four
hours
per
day,
or
at
the
nearest
field
office
if
it
is
not
so
attended.
A
Plan
must
always
be
available
without
advance
notice,
because
an
inspection
might
not
be
scheduled.
You
are
not
required
to
locate
a
Plan
at
an
unattended
facility
because
of
the
difficulty
that
might
ensue
when
emergency
personnel
try
to
find
the
Plan.
However,
you
may
keep
a
Plan
at
an
unattended
facility.
If
you
do
not
locate
the
Plan
at
the
facility,
you
must
locate
it
at
the
nearest
field
office.

Less
than
four
hours;
Inconsistent
requirements.
We
disagree
that
the
rule
provides
mutually
inconsistent
requirements.
If
the
facility
is
not
attended
at
least
four
hours
a
day,
the
Plan
must
be
maintained
at
the
nearest
field
office,
not
the
facility.

State
and
local
agencies.
You
are
not
required
to
file
or
locate
a
Plan
with
a
State
Emergency
Response
Commission
or
Local
Emergency
Planning
Committee
or
other
State
or
local
agency
because
the
distribution
would
unjustifiably
increase
the
125
information
collection
burden
of
the
rule,
and
not
all
committees
or
agencies
may
want
copies
of
SPCC
Plans.
Should
a
State
wish
to
require
filing
of
a
Federal
SPCC
Plan
with
a
State
or
local
committee
or
agency,
it
may
do
so.
No
Federal
requirement
is
necessary.

VI
­
I:
Extension
of
time
­
§112.3(
f)

Background:
In
1991,
we
proposed
to
allow
only
new
facilities
to
apply
for
extensions
of
time
to
comply
with
the
requirements
of
part
112.
The
current
rule
allows
any
facility
to
apply
for
an
extension,
including
existing
fixed
and
mobile
facilities.
The
rationale
for
limiting
extension
requests
to
new
facilities
was
that
existing
fixed
and
mobile
facilities
have
had
since
1974
to
comply
with
the
rule.

Comments:
Amendments.
"While
the
preamble
discussion
of
this
section
mentions
the
requirement
that
plans
be
amended
before
any
change
is
made
and
provides
for
extensions
to
be
granted
by
the
EPA
Regional
Administrator
(RA)
where
immediate
amendment
of
the
SPCC
plan
is
not
practicable,
no
language
to
this
effect
could
be
found
within
the
rule
itself.
...
Consequently,
it
is
unclear
if
such
requirements
will
apply
or
exactly
how
much
time
will
be
available
to
a
facility
to
prepare
an
SPCC
plan
amendment."
(71)

Automatic
extensions.
"BHP
has
already
stated
its
position
that
plans
should
not
be
required
prior
to
beginning
operations.
If
such
a
requirement
is
made,
then
extensions
should
be
automatic
upon
the
filing
of
a
request
for
extension,
so
long
as
the
request
is
made
in
appropriate
form."
(33,
42,
66,
110,
133,
167,
L12)
A
request
for
an
extension
should
be
considered
"routine."
(155)

Plan
requirements.
Criticizes
the
proposed
requirement
to
submit
the
existing
Plan
with
each
extension
request,
because
EPA's
review
of
the
Plan
cannot
practically
be
an
element
of
the
extension
granting
process.
The
language
in
paragraph
(f)(
3)
"would
be
better
say
that
a
facility's
existing
provisions
remain
in
effect
until
they
are
superseded
by
changes
proposed
by
the
facility."
(155)

Response:
Amendments.
We
have
also
added
a
provision
for
an
extension
of
time
to
prepare
and
implement
an
amendment
to
the
Plan,
as
well
as
an
entire
Plan.
We
believe
that
there
may
be
cases
in
which
an
extension
can
be
justified
for
a
Plan
amendment
because
the
same
extenuating
circumstances
may
apply.

Automatic
extensions.
Automatic
extension
requests
are
not
justifiable
because
we
have
extended
the
time
within
which
most
facilities
have
to
prepare
and
implement
Plans.
See
§112.3(
a),
(b),
and
(c).
Also,
under
the
revised
rule,
you
may
request
an
extension
for
the
preparation
and
implementation
of
any
Plan,
or
amendment
to
any
Plan.
See
§112.3(
f).

Plan
requirements.
We
have
broadened
the
scope
of
extension
requests
to
any
facility
that
can
justify
the
request,
because
for
every
type
of
facility
there
may
be
cases
in
126
which
an
extension
can
be
justified.
Existing
fixed
and
mobile
facilities
may
experience
delays
in
construction
or
equipment
delivery
or
may
lack
qualified
personnel,
and
these
circumstances
may
be
beyond
the
control
of,
and
without
the
fault
of,
the
owner
or
operator.
We
also
agree
with
the
commenter
that
the
submission
of
the
entire
Plan
as
a
matter
of
course
is
unnecessary
to
evaluate
each
extension
request.
Therefore,
we
have
amended
the
rule
to
provide
that
the
Regional
Administrator
may
request
your
Plan
if
he
deems
it
appropriate.
But
we
do
not
believe
that
he
will
always
do
so.
It
may
be
necessary
under
some
circumstances.
The
Regional
Administrator
also
retains
discretion
to
request
the
Plan
after
on­
site
review,
or
after
certain
discharges.
See
§112.4(
a)(
9)
and
(d).
We
disagree
with
the
commenter's
proposed
rewrite
of
the
owner
or
operator's
obligations
while
the
request
is
pending
because
the
better
policy
is
to
require
compliance
with
the
rest
of
the
rule
that
is
not
affected
by
the
extension
request,
rather
than
saying
that
the
existing
Plan
continues
in
effect.
127
Category
VII
­
Amendment
to
a
Plan
by
the
RA
VII
­
A:
Registered
agents
­
§112.4(
a)
and
(e)

Background:
Section
112.4
of
the
current
rule
describes:
1)
the
spill
events
for
which
an
owner
or
operator
must
submit
a
Plan
and
other
information
to
the
Regional
Administrator
(RA)
for
review;
2)
the
information
that
must
be
submitted
to
the
RA;
and,
3)
procedures
for
requiring
amendments
to
the
Plan.
In
1991,
we
proposed
several
changes
to
§112.4.
In
§112.4(
a),
we
proposed
to
require
an
owner
or
operator
to
provide
the
RA
with
the
name
and
address
of
any
registered
agent
when
reporting
a
spill
event,
because
a
registered
agent
may
have
information
that
the
RA
needs.
We
also
noted
that
the
RA
may
need
to
contact
the
agent
with
further
questions
or
send
the
reviewed
Plan
back
to
the
agent.
In
§112.4(
e),
we
proposed
to
continue
requiring
that
the
RA
notify
the
facility
owner
or
operator
and
the
registered
agent,
if
any,
if
the
RA
is
proposing
an
amendment
to
the
SPCC
Plan.
We
withdrew
the
1991
proposed
revision
of
§112.4(
a)
in
1997,
and
substituted
a
new
proposal
without
reference
to
a
registered
agent.

Comments:
Definition
of
"registered
agent."
"Since
the
term
clearly
has
a
specific
meaning
for
EPA,
it
should
either
be
added
to
40
CFR
112.2
or
specified
within
the
preamble
to
the
final
rule.
We
would
suggest
EPA
include
this
term
in
40
CFR
112.2
since
this
individual
has
specific
responsibilities
under
40
CFR
112.4."
(33)

Notice
to
facility
and
agent.
We
should
send
the
§112.4
notice
directly
to
the
affected
facility
and
the
registered
agent.
For
a
large
railroad,
it
may
take
days
for
the
affected
facility
to
receive
a
notice
given
to
a
registered
agent.
(57)
"The
only
way
EPA
can
do
this
is
by
having
the
owner
or
operator
notify
EPA
of
the
name
and
address
of
the
registered
agent.
"
(121)

On­
site
personnel.
Because
the
registered
agent
would
not
know
the
facility
SPCC
Plan
as
well
as
on­
site
personnel,
the
RA
should
contact
the
on­
site
safety
and
environmental
coordinator
with
questions
concerning
the
Plan.
(10)

Response:
We
withdrew
the
1991
proposal
that
the
owner
or
operator
supply
the
name
and
address
of
any
registered
agent
to
the
RA
because
we
do
not
always
need
the
information,
and
may
request
it
when
we
do.
We
will
notify
the
registered
agent
of
a
corporation
if
we
know
who
he
is.

The
§112.4(
e)
notification
requirement
for
registered
agents
now
tracks
the
notification
requirement
for
registered
agents
in
§112.1(
f).
In
§112.4(
e)
of
the
final
rule,
we
have
adopted
a
requirement
that
when
the
RA
is
requiring
a
Plan
amendment,
he
must
notify
the
owner
or
operator
and
any
registered
agent,
if
the
registered
agent
is
known.

We
also
will
notify
the
registered
agent,
if
known,
of
the
RA's
determination
in
§112.1(
f)
that
the
facility
owner
or
operator
must
prepare
and
implement
a
Plan.
However,
because
we
have
not
adopted
the
requirement
that
an
owner
or
operator
submit
the
128
registered
agent's
name
and
address
to
the
RA,
we
may
not
know
of
his
registered
agent.
Likewise,
we
have
no
way
of
knowing
who
is
the
on­
site
safety
and
environmental
coordinator.
Therefore,
we
cannot
notify
him.

Definition
of
"registered
agent."
The
concept
of
"agency"
and
"agent"
is
well­
known
in
the
law.
Therefore,
no
definition
of
"registered
agent"
is
necessary
in
these
rules.

VII
­
B:
Discharge
reports
to
EPA
­
§112.4(
a)

Background:
Section
112.4
of
the
current
rule
describes
the
discharges
for
which
a
facility
owner
or
operator
must
submit
the
Plan
and
other
information
to
the
Regional
Administrator
(RA)
for
review,
the
information
that
must
be
submitted
to
the
RA,
and
procedures
for
requiring
amendments
to
the
Plan.
In
the
1991
proposed
rule,
we
proposed
several
changes
to
§112.4.
In
the
1991
proposed
rule,
we
suggested
several
changes
to
§112.4.
Proposed
§112.4(
a)
provided
that
whenever
an
SPCC
facility
discharges
more
than
1,000
gallons
of
oil
in
a
single
spill
event,
as
described
in
§112.1(
b),
in
two
spill
events
within
a
consecutive
twelve
month
period,
the
owner
or
operator
must
submit
to
the
RA
certain
information.

In
§112.4(
a)(
10),
we
proposed
to
require
that
an
owner
or
operator
submit
to
the
RA
information
on
the
nature
and
volume
of
oil
spilled,
in
addition
to
the
information
currently
required
under
§112.4(
a)
because
this
information
would
help
the
RA
identify
problem
areas
where
additional
regulatory
emphasis
may
be
needed.
Section
112.4(
a)(
13)
would
require
the
owner
or
operator
to
provide
"such
other
information
as
the
RA
may
reasonably
require
pertinent
to
the
Plan
or
spill
event."

In
1997,
we
withdrew
the
1991
proposal
for
§112.4(
a)
and
substituted
a
new
proposal.

Comments:
Support
for
proposal.
We
should
require
a
report
within
a
reasonable
time
period
on
the
amount
of
product
recovered
during
cleanup.
(44)

Amount
spilled,
proposed
§112.4(
a)(
10).
Supports
a
requiring
notification
of
"the
nature
and
volume
of
oil
spilled."
(185,
193)

Compliance
with
proposed
requirement
difficult.
It
may
be
impossible
to
retrieve
oil
after
a
spill
to
test
its
composition
and
quantify
"exactly"
what
and
how
much
was
spilled.
(92,
155,
L12)
Violating
so
imprecise
a
requirement
would
subject
the
violator
unjustly
to
Clean
Water
Act
penalty
provisions.
(L12)

Date
and
year
of
initial
facility
operation.
There
is
no
purpose
in
providing
the
date
and
year
of
initial
facility
operation
to
the
RA
every
time
a
spill
occurs,
and
suggested
we
delete
the
requirement.
(33)

Discharges
to
soil.
"The
rule
should
be
altered
so
that
it
is
unambiguous
in
indicating
that
all
spills
of
the
threshold
amounts
will
trigger
the
need
to
alter
the
SPCC
Plan."
A
spill
to
soil,
"poses
a
risk
to
surface
water,
even
if
the
immediate
impact
is
only
on
soil
129
or
groundwater."
Noting
that
SPCC
Plans
cover
"only
one
661
gallon
above­
ground
storage
tank.
Amendment
of
the
SPCC
Plan
for
such
a
facility
will
never
be
required
even
if
the
tank
bursts
every
day,
releasing
all
of
its
contents
onto
dry
soil.
Surely
the
intent
of
this
regulation
is
not
to
deem
such
spills
as
routine."
(43)

Failure
analysis.
The
term
"failure
analysis"
in
§112.4(
a)(
9)
is
ambiguous
and
we
should
define
it.
(28,
58,
101)

"Other"
information,
proposed
§112.4(
a)(
13).
Section
112.4(
a)(
13)
is
"overly
broad
and
violates
due
process."
(58)

Threshold
for
§112.4(
a).

100
gallons,
single
event.
We
should
decrease
the
quantity
of
oil
spilled
during
a
spill
event
to
trigger
§112.4
applicability
to
100
US
gallons
for
a
single
event.
A
100
gallon
spill
is
a
significant
spill
event,
and
we
should
not
permit
an
owner
or
operator
to
defer
amending
a
Plan
"in
the
presence
of
smaller
spill
events."
(43)

25
barrels
single
event,
50
barrels
two
events.
The
trigger
should
be
a
single
spill
greater
than
25
barrels
or
two
spills
of
50
barrels
or
more
within
twelve
months.
Unless
we
set
a
"de
minimis"
amount
for
two
spill
events,
an
owner
or
operator
would
have
to
submit
"a
considerable
amount
of
information"
for
all
spills
–
even
spills
of
"a
few
drips."
(187)

100
barrels
single
event,
50
barrels
two
events.
"API
recommends
that
EPA
change
the
requirement
to
one
single
spill
event
of
more
than
100
barrels
or
two
spills
of
more
than
50
barrels
each
in
any
consecutive
twelve
month
period.
There
are
numerous
large
oil
fields
in
the
coastal
area
which
have
an
extensive
network
of
flowlines,
well
jackets,
and
platforms.
Even
with
all
the
precautions
taken,
it
would
not
be
unlikely
for
more
than
one
spill
of
a
de
minimis
size
(e.
g.,
less
than
one
ounce
of
oil)
to
occur
in
one
day.
Under
these
proposed
requirements,
the
O/
O
would
have
to
spend
valuable
resources
filling
out
paperwork
and
reporting
to
EPA
rather
than
trying
to
prevent
reoccurrence."
(67,
91,
173)

Response:
Support
for
proposal.
We
appreciate
commenter
support.
We
withdrew
the
proposal
for
§112.4(
a)
in
the
proposed
1997
rule
and
substituted
new
language
for
that
section.

Date
and
year
of
initial
facility
operation.
In
1997,
we
withdrew
the
1991
proposal
for
§112.4(
a)
and
substituted
a
new
proposal.
We
agree
that
it
is
an
undue
burden
on
an
owner
or
operator
to
submit
information
on
the
date
and
year
a
covered
facility
began
operations.
That
information
is
not
always
necessary
in
order
to
accurately
assess
the
discharge
or
to
require
appropriate
action.
When
it
is
necessary,
the
Regional
130
Administrator
may
request
it.
Therefore,
we
have
eliminated
the
requirement
to
always
submit
such
information
after
certain
discharges.

Discharges
to
soil.
We
have
never
proposed
such
a
requirement
for
SPCC
purposes.
The
purpose
of
the
Act
is
to
prevent
discharges
as
described
in
§112.1(
b),
not
discharges
onto
soil.
A
spill
of
oil
onto
soil
may
or
may
not
ever
become
such
a
discharge.

Failure
analysis.
"Failure
analysis"
means
a
study
of
the
equipment
or
procedures
to
understand
the
reasons
why
such
equipment
or
procedures
did
not
function
properly.
The
methods
of
such
analysis
should
be
determined
according
to
industry
standards.

"Other"
information,
proposed
§112.4(
a)(
13).
We
disagree
that
proposed
§112.4(
a)(
13),
§112.4(
a)(
9)
in
the
final
rule,
is
overly
broad
or
violates
due
process.
EPA
has
authority
under
sections
308
and
311(
m)
of
the
Clean
Water
Act
to
require
an
owner
or
operator
to
provide
information
concerning
requirements
of
the
Act.

Threshold
for
§112.4(
a).
We
agree
that
a
higher
threshold
of
reporting
discharges
is
justifiable
because
we
believe
that
only
larger
discharges
should
trigger
an
EPA
obligation
to
review
a
facility's
prevention
efforts.
We
also
agree
that
a
higher
threshold
should
trigger
a
facility's
obligation
to
submit
information
and
possibly
have
to
take
further
prevention
measures.
Therefore,
we
have
changed
the
threshold
for
reporting
after
two
discharges
as
described
in
§112.1(
b).
Under
the
revised
rule,
if
you
are
the
owner
or
operator
of
a
facility
subject
to
this
part,
you
must
only
submit
the
required
information
when
in
any
twelve
month
period
there
have
been
two
discharges
as
described
in
§112.1(
b),
in
each
of
which
more
than
42
U.
S.
gallons,
or
one
barrel,
has
been
discharged.
The
other
reporting
threshold
of
1,
000
gallons
in
any
a
single
discharge
as
described
in
§112.1(
b)
remains
the
same.

We
disagree
that
a
sheen
caused
by
a
discharge
as
described
in
§112.1(
b)
over
the
threshold
amount
that
disappears
within
24
hours
should
not
require
submission
of
information.
The
discharge
itself
may
indicate
a
serious
problem
at
the
facility
which
needs
to
be
corrected.
The
discharge
report
may
give
us
the
information
necessary
to
require
specific
correction
measures.

VII
­
C:
General/
other
­
§112.4
VII­
C­
1
Supplying
discharge
information
to
the
States
­
§112.4(
c)

Background:
Under
§112.4(
c)
of
the
current
rule,
an
owner
or
operator
must
submit
to
the
State
water
pollution
control
agency
or
agencies,
a
copy
of
the
information
submitted
to
the
RA
under
§112.4(
a).
In
1991,
we
proposed
to
require
that
an
owner
or
operator
submit
the
information
to
the
State
oil
pollution
control
agency
or
agencies.

Comments:
Support
for
proposal.
"The
proposed
change
in
section
112.4(
c),
which
requires
the
operator
to
send
a
copy
of
the
information
provided
the
Regional
131
Administrator
to
the
State
agency
in
charge
of
oil
pollution
control
rather
than
the
agency
in
charge
of
water
pollution,
is
helpful."
"...(
I)
n
Texas,
as
in
other
States,
more
than
one
agency
has
statutory
jurisdiction
over
oil
pollution
control."
(76,
99,
193)

Authority.
"USEPA
does
not
have
authority
under
the
Clean
Water
Act
to
require
an
owner
of
a
facility
to
file
a
copy
of
the
sixty
day
report
with
the
responsible
state
agency
and
therefore
this
requirement
is
unlawful.
USEPA
should
remove
this
requirement."
(58)

Duplicative
requirement.
"Operator
should
not
be
required
to
forward
this
information
to
a
state
agency
also.
If
EPA
is
to
regulate
the
SPCC,
this
requirement
is
redundant
and
serves
no
purpose."
(28,
101)
"We
disagree
with
the
agency
proposal
that
owners
or
operators
be
required
to
furnish
the
Regional
Administrator
with
information.
If
the
owner
or
operator
provides
a
copy
to
the
state
agency
in
charge
of
oil
pollution
control,
we
believe
this
to
be
sufficient.
The
majority
of
states
review
the
plan
and
submit
written
suggestions
or
improvements,
etc.
Submission
of
additional
paperwork
to
the
Regional
Administrator
is
not
consistent
with
the
Paperwork
Reduction
Act
as
well
as
it
would
not
serve
any
useful
purpose."
(82)

Editorial
comment.
We
should
require
sending
the
information
to
the
appropriate
"agency
or
agencies."
(99)

EPA
guidance.
We
should
tell
each
owner
or
operator
which
State
agency
should
get
§112.4(
a)
information.
(76)

Financial
assistance.
States
cannot
participate
in
reviewing
§112.4(
a)
information
without
financial
assistance.
We
should
"consolidat(
e)
programs
to
eliminate
duplicate
agency
involvement."
(111)

Required
Plan
amendments.
We
should
specify
that
only
the
RA
may
require
an
Plan
amendment
–
even
if
a
State
makes
recommendations.
We
should
clarify
the
regulatory
text
to
avoid
this
ambiguity,
adding
that,
"EPA
may
require
implementation
of
State
agency
recommendations
only
if
they
are
within
the
scope
of
the
regulations.
State
agencies
receiving
incident
reports
should
review
the
reports
in
the
context
of
the
incident
at
hand
and
use
this
information
for
its
intended
purpose
of
advising
the
RA
on
possible
amendments
to
the
Plan."
(83)

State
water
control
agencies.
The
appropriate
agency
to
receive
information
is
the
State
water
control
agency,
and
that
sending
information
to
the
oil
pollution
control
agency
would
"most
likely
mislead
an
operator,
the
public,
an
officer
of
the
court
and/
or
EPA
itself."
(L12)

Response:
Support
for
proposal.
We
appreciate
the
comment
supporting
our
proposal
to
send
§112.4(
a)
discharge
information
to
the
State
oil
pollution
control
agency
or
agencies.
132
Legal
authority.
We
have
ample
legal
authority
to
finalize
this
rule.
A
similar
rule
has
been
in
effect
since
1974.
Section
311(
j)(
1)
of
the
CWA
authorizes
the
Federal
government
(and
EPA
through
delegation)
to
establish
"procedures,
methods,
and
equipment
and
other
requirements
for
equipment
to
prevent
discharges
of
oil...."
Section
112.4(
c)
of
this
rule
is
a
procedure
to
help
prevent
discharges
that
fall
within
the
scope
of
that
statutory
provision.
It
enables
States
to
learn
of
discharges
reported
to
EPA
and
to
make
recommendations
as
to
further
procedures,
methods,
equipment,
and
other
requirements
that
might
prevent
such
discharges
at
the
reporting
facility.

We
can
only
implement
State
agency
suggestions
that
are
within
the
scope
of
our
authority
under
section
311
of
the
CWA.

In
general.
The
commenter
is
correct
that
the
SPCC
program
is
a
Federal
program,
but
we
believe
that
in
working
with
the
States,
we
can
improve
the
Federal
program
through
coordination
with
State
oil
pollution
prevention
programs.
Therefore,
we
believe
that
the
information
provided
to
States
is
neither
redundant
nor
unnecessary.
Nor
is
the
section
misleading;
it
clearly
states
the
obligation
of
the
owner
or
operator.

State
agency
review.
We
modified
the
1991
proposal
on
the
commenters'
suggestion
to
include
notice
to
any
appropriate
State
agency
in
charge
of
oil
pollution
control
activities,
since
there
may
be
more
than
one
such
agency
in
some
States
and
all
may
have
need
for
the
information.
We
do
not
list
such
agencies
in
the
rule,
as
a
commenter
suggested,
because
the
names
and
jurisdiction
of
the
State
agencies
are
subject
to
change.
It
is
the
reporter's
obligation
to
learn
which
State
agencies
receive
the
discharge
reports.
Most
States
publish
documents
on
an
ongoing
basis,
similar
to
the
Federal
Register,
which
publicize
relevant
regulatory
information.

We
do
not
provide
State
agencies
funds
to
review
these
discharge
reports
due
to
budgetary
constraints.
While
we
assume
that
many
States
review
these
reports
carefully,
we
cannot
require
them
to
do
so.
Thus,
this
action
is
not
an
unfunded
mandate
from
the
Federal
government
to
the
States.
But
if
States
do
review
the
reports,
they
do
so
at
their
own
expense.

VII­
C­
2
Amendment
of
Plans
required
by
the
RA
­
§112.4(
d)

Background:
In
§112.4(
d),
we
proposed
adding
language
giving
the
RA
authority
to
approve
a
Plan
after
reviewing
the
materials
submitted
under
§112.7(
d).

Comments:
Appeals.
Asks
what
the
procedure
is
for
appealing
an
RA's
decision
(on
Plan
approval)
to
the
Administrator.
(28,
101)

PE
role
in
RA­
required
amendments.
"...(
A)
ny
`terms
of
amendment'
made
by
the
RA
must
be
signed
and
sealed
by
an
Agency
or
Agency
retained
professional
engineer."
When
the
RA
requires
a
Plan
amendment,
"the
certifying
PE
(has)
no
alternative
but
to
certify
the
SPCC
Plan
or
resign."
In
such
cases,
EPA
must
certify
the
change
as
meeting
good
engineering
practice,
and
"the
RA
must
be
held
accountable
legally
and
133
financially"
when
he
mandates
a
change
that
"causes
or
results
in
an
oil
spill."
(48,
63,
67,
72,
85,
110,
170,
173)

Plan
review
and
approval.
Proposed
§112.4(
d)
gives
the
RA
"unlimited
authority"
to
reject
SPCC
Plans.
(28,
101)
We
should
minimize
or
eliminate
"any
activities
requiring
agency
approvals,"
given
the
"historical
difficulty
of
getting
dedicated
resources
to
perform
professional
work
related
to
these
reviews."
(111)
Having
the
RA
approve
a
Plan
"puts
an
entirely
new
dimension
in
this
process,"
and
asked
us
to
consider
the
approach.
(121)
"Plan
review
after
a
spill
event
by
the
EPA
Regional
Administrator
is
under
the
conditions
identified
in
40
CFR
112.4
are
excessive
and
burdensome
both
to
the
EPA
and
regulated
community.
EPA
should
on
a
case
by
case
basis
review
SPCC
Plans
after
a
spill
event
if
the
review
is
deemed
necessary
by
the
Regional
Administrator
or
his/
her
staff."
(192)

Time
limit
on
review.
"The
current
language
of
the
referenced
sentence
could
imply
that
the
Regional
Administrator
must
approve
or
request
amendments
to
the
SPCC's
plans.
In
fact,
the
Regional
Administrator
does
not
have
to
take
such
affirmative
action,
unless
he/
she
so
chooses.
Plan
approval
is
not
necessary
for
the
owner/
operator
to
continue
operations
of
a
facility.
Therefore,
once
a
plan
is
submitted,
the
owner/
operator
should
be
given
a
certain
specified
waiting
period
for
approval,
after
which
he/
she
can
consider
the
submitted
plan
is
adequate."
(67)

Response:
Appeals.
Because
we
have
not
adopted
RA
review
and
approval
of
Plans,
no
appeals
process
is
necessary
for
a
decision
to
reject
a
Plan.
An
appeals
process
exists
for
required
Plan
amendments.
See
§112.4(
e).

PE
role
in
RA­
required
amendments.
A
PE
must
certify
any
technical
amendment
to
an
SPCC
Plan
–
irrespective
of
whether
the
owner
or
operator,
or
the
RA,
initiates
the
amendment
process.
When
the
RA
decides
a
Plan
amendment
is
necessary,
it
is
the
responsibility
of
the
owner
or
operator
to
draft
such
amendment
and
implement
it.
The
PE
must
certify
that
any
amendment
has
been
prepared
in
accordance
with
good
engineering
practice.

Plan
review
and
approval.
We
have
deleted
the
provision
that
would
have
allowed
RA
approval
of
Plans.
We
have
decided
not
to
create
a
new
class
of
SPCC
Plans
which
require
EPA
approval,
either
Plans
submitted
following
certain
discharges
as
required
by
§112.4(
a)
or
Plans
with
contingency
plans,
because
we
do
not
believe
such
approval
is
necessary
in
order
to
ensure
effective
Plans.

Time
limit
on
review.
A
time
limit
on
RA
review
of
a
Plan
is
also
moot
because
we
withdrew
the
proposal
which
would
have
allowed
RA
review
and
approval
of
a
Plan.

VII­
C­
3
Implementation
of
required
amendments
­
§112.4(
e)

Comments:
Implementation
time
for
required
amendments.
134
"Longer
than
6
months."
The
rule
"appears
to
contemplate
a
longer
period
than
six
months."
We
should
change
the
language
to
read
unless
the
RA
specifies
"a
longer
time"
in
place
of
"another
date."
(42)
Six
months
may
be
an
insufficient
time
to
implement
an
amendment
requiring
new
construction
to
the
facility.
(83,
143)

One
year
(with
construction).
Six
months
is
appropriate
if
the
change
is
"purely
operational,"
but
that
the
implementation
period
should
be
"one
year
(after
obtaining
required
permits)
in
a
case
where
construction
of
facilities
(is)
required."
(83)

Extensions,
reasons
for.
More
than
6
months
should
be
allowed
for
implementation
if
"the
facility
can
show
that
the
equipment,
parts,
etc.,
are
not
available
to
be
installed
in
time,
or
if
qualified
contractors
are
not
available
to
do
the
installation
on
time."
(143)

Who
receives
notice.
We
should
"require
that
the
RA
provide
notice
to
the
facility
operator,
the
facility
improvement
owner,
and
the
facility
landowner.
The
reason
the
expanded
notice
is
desirable
is
that
a
major
problem
may
be
addressed
by
the
facility
operator
and
the
EPA,
without
the
knowledge
and/
or
consent
of
the
facility
improvements
owner
and
the
facility
landowner."
(47)

Response:
In
1991,
we
proposed
no
change
in
the
six
month
timeline
for
implementing
a
required
Plan
amendment.
We
agree
that
in
some
cases
that
six
months
are
not
sufficient
to
implement
an
amendment.
We
have
therefore
amended
the
rule
to
allow
an
owner
or
operator
to
petition
the
RA
for
an
extension
to
implement
an
amendment.
See
§112.3(
f)(
1).
Nonavailability
of
qualified
personnel,
or
delays
in
construction
or
equipment
delivery
that
are
beyond
the
control
of,
and
that
are
not
the
fault
of
the
owner
or
operator,
may
justify
an
extension
request.

Who
receives
notice.
The
rule
requires
notice
only
to
the
owner
or
operator
of
the
facility,
and
the
registered
agent,
if
any
and
if
known.
Notice
from
EPA
to
the
facility
improvements
owner
and
landowner
is
unnecessary
because
these
matters
can
and
should
be
handled
between
the
facility
owner
or
operator
and
the
owner
or
operator
of
the
improvements
or
the
landowner.

VII­
C­
4
Appeals
of
required
amendments
­
§112.4(
f)

Comments:
In
§112.4(
f),
the
word
"decision"
is
ambiguous,
and
we
should
replace
it
with
"ruling,"
a
less
ambiguous
term.
(70)

Response:
"Decision"
is
a
commonly
used
legal
term
which
in
this
context
means
the
final
determination
of
the
RA
when
considering
the
appeal
of
a
required
amendment.
135
Category
VIII:
Amendment
to
a
Plan
by
the
owner
or
operator
VIII
­
A:
Plan
amendment
by
an
owner
or
operator
­
§112.5(
a)

Background:
In
§112.5(
a)
of
the
current
rule,
an
owner
or
operator
of
a
facility
subject
to
§112.3(
a),
(b)
or
(c)
must
amend
his
Plan
in
accordance
with
§112.7
when
there
is
a
change
in
facility
design,
construction,
operation,
or
maintenance
which
materially
affects
the
facility's
potential
for
the
discharge
of
oil
into
or
upon
navigable
waters
or
adjoining
shorelines.
An
owner
or
operator
must
implement
such
amendment
as
soon
as
possible,
but
not
later
than
six
months
after
the
change
occurs.

In
1991,
we
proposed
in
§112.5(
a)
to
require
an
owner
or
operator
to
amend
his
Plan
when
making
any
material
changes
in
facility
design,
construction,
operation,
or
maintenance
affecting
the
facility's
potential
for
discharge
of
oil,
unless
the
Regional
Administrator
grants
an
extension.
In
the
preamble
we
noted
that
an
owner
or
operator
must
amend
the
Plan
before
making
any
material
changes
in
the
specified
categories.
We
also
listed
examples
in
the
proposed
rule
of
facility
changes
requiring
Plan
amendment.

Comments:
Support
for
proposal.
"As
with
Section
112.3,
we
feel
that
this
proposal
has
merit,
because
it
requires
plant
personnel
to
evaluate
the
spill
potential
of
their
planned
additions
before
they
are
built."
(80,
181,
L1)

Accumulation
of
changes.
"APS
proposes
that
language
be
added
to
allow
facilities
that
perform
minor
modifications
on
a
regular
basis,
be
allowed
to
`accumulate'
those
changes
for
a
period
of
six
months,
then
update
the
plan.
In
addition,
APS
suggest
these
`minor
modifications'
be
defined
as
modifications
that
do
not
need
additional
containment
or
spill
prevention
systems
to
prevent
oil
from
reaching
`waters
of
the
U.
S.
'"
(74)

Alternatives
to
amendment.

Fractionization
tank.
"...(
U)
nless
language
were
added
to
exclude
fractionization
tanks
from
the
SPCC
program,
each
time
a
frac
tank
is
used
or
moved
to
a
new
location,
a
modification
to
the
facility­
specific
SPCC
plan
would
be
required
per
112.5(
a).
Frac
tanks
are
often
used
to
store
oil
for
short
periods
of
time
while
maintenance
or
workover
operations
are
underway.
The
use
of
frac
tanks
is
of
very
short
duration
and
does
not
necessarily
increase
the
potential
for
a
discharge."
(167)

Log
book.
Instead
of
amendment
for
standard
facility
activities,
"BP
proposes
instead
than
an
operations
log
book
of
such
routine
activities
be
maintained
to
document
routine
activities
and
what
measures
were
taken
to
maintain
the
spill
prevention
and
response
integrity
of
the
facility.
Additionally,
a
facility
status
board
showing
the
status
of
storage
tanks,
main
control
valves,
dikes
and
dike
drain
valves,
catchment
basins,
etc.,
could
be
posted
in
a
prominent
area
to
136
keep
all
pertinent
employees
informed
of
the
changing
conditions
at
a
facility."
(96)

Owner/
operator
review
­
common
repairs,
etc.
"...(
M)
ost
plans
can
accommodate
many
changes
without
amending
the
Plan.
This
would
be
especially
true
of
a
facility
that
has
site­
wide
secondary
containment.
Operators
should
be
allowed
to
document
that
they
have
reviewed
such
changes,
and
have
either
determined
that
an
amendment
to
the
Plan
is
not
required,
or
have
requested
a
review
from
the
certifying
PE.
The
PE
should
be
allowed
to
document
that
he/
she
has
reviewed
the
planned
changes,
and
has
concluded
an
amendment
is
not
necessary,
that
further
study
is
required,
or
that
an
amendment
is
required."
(76)
"Pennzoil
opposes
any
requirement
that
plans
be
amended
prior
to
all
changes
to
the
tank
structure.
Pennzoil
believes
that
flexibility,
such
as
that
provided
in
the
current
rule
for
amendments
to
SPCC
plans,
is
essential
to
ensure
that
operators
of
facilities
have
the
ability
to
make
immediate
modifications
or
repairs
to
oil
piping
or
storage
systems.
...
To
delay
the
modification
until
a
plan
can
be
revised
and
reviewed
by
a
PE
or
to
wait
on
the
approval
by
the
EPA
RA
of
a
requested
extension
of
time
could
be
detrimental."
(71,
113)

Material
changes.

"Adverse"
effect.
"The
standard
for
operation
and
maintenance
changes
should
be
the
same
as
that
for
design
and
construction
changes–
a
change
that
would
result
in
a
material
adverse
effect
to
the
potential
of
a
facility
to
discharge
oil."
(35)

Clarification
needed.
We
should
clarify
what
it
means
to
materially
affect
a
facility's
potential
to
discharge
oil.
(96,
118,
164,
189)

Examples
of
material
changes.

Support
for
EPA
list.
Support
for
proposed
list
of
examples
that
may
constitute
a
material
change
requiring
Plan
amendment.
(102,
118,
170,
L8)

Opposition
to
EPA
list.
"A
strict
interpretation
of
the
proposed
rule
would
appear
to
require
an
amendment
for
any
such
change
(and
possibly
a
site
visit
by
the
certifying
engineer).
This
is
excessive.
The
people
entrusted
to
the
operation
of
such
a
facility
should
be
able
to
evaluate
most
conditions
and
determine
if
an
amendment
is
necessary."
(76)
We
should
narrow
the
examples
of
material
changes.
The
list
is
too
broad.
(33,
34,
58,
75,
101,
125,
164,
165,
167,
173,
L8,
L12,
1155
(1993
commenter)).
We
should
create
an
inclusive
list
of
material
changes.
(189)

Examples
are
not
definitive
for
all
facilities.
"API
believes
that
the
wording
in
Section
112.5(
a)
should
be
changed
to
read
`Examples
of
changes
that
may
137
require
amendment
to
the
Plan
include,
but...
'
While
API
agrees
with
the
requirement
to
report
facility
changes
that
materially
affect
a
facility's
potential
to
discharge
oil,
the
examples
of
changes
requiring
amendment
of
the
Plan
would
not,
in
most
instances,
materially
affect
a
facility's
oil
discharge
potential.
In
many
facilities
such
as
refineries,
the
examples
of
changes
(in
the
proposed
regulations),
requiring
SPCC
Plan
amendment
and
subsequent
recertification
by
a
PE
are
daily
occurrences."
(67,
86,
125)

Change
of
product.
"An
amendment
to
the
SPCC
Plan
should
also
be
required
when
there
is
a
change
in
the
product
stored
within
the
tank.
Such
amendment
should
address
the
permeability
of
the
secondary
containment
system,
material
compatibility,
etc.
for
the
product
being
stored."
(111)
"Changing
a
product
in
a
tank
or
cleaning
a
tank
should
not
be
considered
commissioning
or
decommissioning
a
tank."
(143)

Oil
storage
or
transfer.
We
should
clarify
that
only
"systems
and
operations
directly
related
to
oil
storage
or
transfer
which
may
impact
the
environment"
may
require
Plan
amendment
under
§112.5(
a).
(62)

Piping
systems.
"For
instance,
the
replacement
of
a
piping
system
is
listed
as
a
type
of
change
that
would
require
amending
the
Plan.
Is
this
true
when
the
piping
replacement
is
made
in
accordance
with
the
same
industry
standards
as
the
original,
serves
the
same
function
as
the
original,
and
is
replaced
in
exactly
the
same
location.
What
about
adding
a
new
piping
run
to
an
already
existing
run
of
6
pipes
carrying
similar
types
of
materials?
BP
suggests
that
neither
of
these
changes
are
`substantial'
but
the
proposed
rule,
as
stated,
could
be
interpreted
otherwise."
(96)

Tanks
over
5,
000
gallons.
We
should
replace
the
word
tanks
with
tanks
over
5,000
gallons
in
our
listing
of
examples.
(L8)

Changes
which
are
not
material.

Commissioning
tanks,
etc.
Commissioning,
decommissioning,
replacement,
reconstruction,
or
movement
of
tanks
(28,
37,
58,
66,
71,
96,
101,
113,
164,
165,
L2,
L15)

Contact
list.
Non­
technical
changes
to
the
Plan
(e.
g.,
contact
list,
phone
numbers,
names,
etc.)
(72,
121,
190)

Inspection
documents.
Non­
technical
changes
to
the
Plan,
such
as
frequency
of
inspection
and
inspection
documents.
(72,
76,
165,
L7)

Piping
systems.
Reconstruction,
replacement,
or
installation
of
piping
systems.
(28,
66,
96,
101,
113,
165,
L2,
L15).
138
Routine
operation
and
maintenance.
Revising
standard
operation
or
maintenance
procedures
at
a
facility
(28,
35,
70,
101,
102,
165,
167,
L6)
Minor
alterations
or
certain
kinds
of
construction
–
such
as
replacing
a
pump
or
tank
in­
kind
or
routine
valve
replacements
–
are
not
material
changes.
(155,
164)

Revision
of
standard
operation
or
maintenance
procedures
at
a
facility.
We
should
clarify
what
constitutes
a
revision
of
standard
operation
or
maintenance
procedures
at
a
facility.
(L8)

Time
line
for
amendment
implementation.

Opposition
to
proposed
time
line.
"Proposed
section
112.5
would
require
an
amendment
to
an
SPCC
Plan
before
there
is
a
change
in
facility
design,
construction,
operation,
or
maintenance
of
the
facility
that
materially
affects
the
facility's
potential
to
discharge
oil.
IFTOA
believes
that
the
proposal
is
too
broad.
Numerous
design
changes
are
proposed
as
facilities
are
evaluated.
Designs
are
made,
modified,
or
discarded.
Requiring
an
amendment
every
time
a
facility
design
is
substantially
changed
will
subject
owners
and
operators
to
significant
costs,
wasted
efforts
and
inefficiencies.
Only
when
a
material
change
has
actually
been
implemented,
such
as
completion
of
construction,
should
an
amendment
to
the
Plan
be
required."
(54,
57,
68,
71,
75,
77,
103,
125,
155,
165,
167,
169,
170,
173,
191,
L2,
L15,
L30)

Alternative
time
frames.
Start­
up
of
operations
(103,
125,
155,
165,
170);
after
the
completion
of
facility
changes
or
modifications
(54,
57,
75).
After
a
design
change,
but
before
implementing
that
change
(77);
after
installing
new
structures
and
equipment,
but
before
operation
(L2);
and
during
the
next
triennial
review
(71).
We
should
require
owners
or
operators
to
amend
the
Plan
when
there
is
a
material
change
in
facility
design,
construction,
operation,
or
maintenance.
(75)
For
multi­
well
drilling
programs,
we
should
require
owners
or
operators
to
amend
the
Plan
after
completing
a
drilling
program.
(167)

"Adequate
time."
We
should
allow
owners
or
operators
of
existing
facilities
adequate
time
for
Plan
amendment.
(71)

30
days.
Thirty
days
after
completing
new
construction,
and
make
the
extant
Plan
temporary
during
that
period.
(37)

90
days.
We
should
allow
owners
or
operators
of
exploration
and
production
facilities
and
small
gas
processing
operations
90
days
to
amend
the
Plan
following
any
facility
change.
(114)

6
months.
(67,
91,
110,
113,
167,
173,1155
(1993
commenter)).
For
implementing
an
amendment,
we
should
allow
owners
or
operators
six
months
following
facility
changes.
(35,
78,
101,
145)
We
should
require
implementing
the
Plan
amendment
within
six
months
of
a
new
facility's
initial
operations
or
139
additions
to
an
existing
facility.
The
extant
Plan
should
be
temporary
during
that
period.
(134)
We
should
allow
owners
or
operators
six
months
to
amend
the
Plan
following
a
change
that
does
not
increase
the
facility's
oil
discharge
potential,
but
require
a
Plan
amendment
before
a
change
that
increases
oil
discharge
potential.
(190)

Emergencies.
The
implementation
time
line
could
be
detrimental
in
an
emergency,
because
an
owner
or
operator
could
not
make
immediate
facility
modifications
or
repairs
without
first
amending
the
Plan.
(71,
191)

When
amendment
is
necessary.

Changes
consistent
with
existing
Plan.
We
should
not
require
amendment
of
SPCC
Plans
for
facility
changes
consistent
with
the
existing
Plan.
(31,
86,
160,
1155
(1993
commenter))

Changes
in
discharge
potential.
We
should
require
Plan
amendment
for
replacing
equipment
only
if
the
facility's
oil
discharge
potential
is
materially
changed.
(31,
160)

Decrease
in
discharge
potential.
We
have
no
environmental
justification
for
imposing
amendment
costs
when
owners
or
operators
make
changes
that
decrease
a
facility's
discharge
risk.
(125)

Increase
in
discharge
potential.
"APC
recommends
the
wording
in
this
section
reflect
an
amendment
is
required,
whenever
a
facility's
potential
for
discharge
of
oil
is
changed
or
increased.
The
removal
of
equipment
decreases
the
facility's
potential
and
appropriate
documentation
should
be
placed
in
the
Plan
and
be
amended
during
the
three
year
review
process."
(25,
35,
66,
71,
72,
98,
101,
118,
125,
167,
L12)

Changes
"significantly
impacting
the
environment."
We
should
require
owners
or
operators
to
amend
the
Plan
only
for
changes
that
can
significantly
impact
the
environment.
(L8)

Changes
warranting
amendment.
"We
recommend
that
current
SPCC
Plans
be
allowed
to
remain
intact
as
currently
written
until
changes
occur
to
existing
oil
storage
facilities
which
warrant
SPCC
Plan
amendments."
(79)

"Indicia
of
problems."
Amendments
should
be
made
"when
there
are
indicia
of
problems."
(43)

Response:
Support
for
proposal.
We
appreciate
commenter
support.
140
Accumulation
of
changes.
An
owner
or
operator
must
amend
the
Plan
when
there
is
a
material
change
at
a
facility.
Therefore,
he
may
not
accumulate
material
changes
for
six
months
before
amending
the
Plan.

Alternatives
to
amendment.
We
disagree
that
owner/
operator
review
of
facility
changes
is
a
substitute
for
Plan
amendment.
When
no
amendment
is
required
because
there
is
no
material
change,
there
is
nothing
to
do.
When
amendment
is
required,
it
must
be
certified
by
a
PE.
We
distinguish
this
review
situation
from
the
technological
review
mandated
under
§112.5(
b).
Under
that
provision,
the
owner
or
operator
may
certify
that
there
has
been
a
review
and
that
he
will
not
amend
the
Plan
as
a
result.

Log
book.
We
agree
that
an
owner
or
operator
may
document
routine
activities
in
an
operations
log
book
rather
than
require
a
Plan
amendment.
However,
in
the
event
of
a
material
change
at
a
facility,
a
log
book
entry
is
no
substitute
for
Plan
amendment.

Material
changes.
We
appreciate
commenter
support
for
our
proposed
examples
of
facility
changes
that
constitute
a
material
change.
A
material
change
is
one
that
may
either
increase
or
decrease
the
potential
for
a
discharge.
We
believe
that
an
amendment
is
necessary
when
a
facility
change
results
in
a
decrease
in
the
volume
stored
or
a
decrease
in
the
potential
for
an
oil
spill
because
EPA
needs
this
information
to
determine
compliance
with
the
rule.
For
example,
the
amount
of
secondary
containment
required
depends
on
the
storage
capacity
of
a
container.
We
agree
with
the
commenter
that
the
rule
should
be
worded
to
indicate
that
the
examples
are
for
illustration
only,
because
the
items
in
the
list
may
not
always
trigger
amendments,
and
because
the
list
is
not
exclusive.
Only
changes
which
materially
affect
operations
trigger
the
amendment
requirement.
Ordinary
maintenance
or
non­
material
changes
which
do
not
affect
the
potential
for
the
discharge
of
oil
do
not.

We
disagree
that
decommissioning
of
a
container
that
results
in
permanent
closure
of
that
container
is
not
a
material
amendment.
Decommissioning
a
container
could
materially
decrease
the
potential
for
a
discharge
and
require
Plan
amendment,
unless
such
decommissioning
brings
the
facility
below
the
regulatory
threshold,
making
the
preparation
and
implementation
of
a
Plan
no
longer
a
requirement.
We
also
believe
that
the
oversight
of
a
Professional
Engineer
is
necessary
to
ensure
that
the
container
is
in
fact
properly
closed.

We
agree
that
replacement
of
tanks,
containers,
piping,
or
equipment
may
not
be
a
material
change
if
the
replacements
are
identical
in
quality,
capacity,
and
number.
However,
a
replacement
of
one
tank
with
more
than
one
identical
tank
resulting
in
greater
storage
capacity
is
a
material
change
because
the
storage
capacity
of
the
facility,
and
its
consequent
discharge
potential,
have
increased.
The
addition
of
a
new
piping
run
to
an
already
existing
run
of
6
pipes
carrying
similar
types
of
materials
may
likewise
be
a
material
change
because
it
may
reflect
a
change
in
storage
capacity
or
may
affect
the
integrity
of
the
secondary
containment
system.
141
Changes
of
product.
We
have
added
to
the
list
of
examples,
on
a
commenter's
suggestion,
"changes
of
product."
We
added
"changes
of
product"
because
such
change
may
materially
affect
facility
operations
and
therefore
be
a
material
change.
An
example
of
a
change
of
product
that
would
be
a
material
change
would
be
a
change
from
storage
of
asphalt
to
storage
of
gasoline.
Storage
of
gasoline
instead
of
asphalt
presents
an
increased
fire
and
explosion
hazard.
A
switch
from
storage
of
gasoline
to
storage
of
asphalt
might
result
in
increased
stress
on
the
container
leading
to
its
failure.
Changes
of
product
involving
different
grades
of
gasoline
might
not
be
a
material
change
and
thus
not
require
amendment
of
the
Plan
if
the
differing
grades
of
gasoline
do
not
substantially
change
the
conditions
of
storage
and
potential
for
discharge.

A
change
in
service
may
also
be
a
material
change
if
it
affects
the
potential
for
a
discharge.
A
"change
in
service"
is
a
change
from
previous
operating
conditions
involving
different
properties
of
the
stored
product
such
as
specific
gravity
or
corrosivity
and/
or
different
service
conditions
of
temperature
and/
or
pressure.
Therefore,
we
have
amended
the
rule
to
add
"or
service"
after
the
phrase
"change
of
product."

Revision
of
standard
operation
or
maintenance
procedures
at
a
facility.
A
revision
of
a
standard
operation
or
maintenance
procedure
is
a
change
in
such
operation
or
procedure
that
may
materially
affect
the
facility's
potential
for
discharge.
If
it
does,
it
must
be
the
subject
of
an
amendment
to
the
Plan.

Time
line
for
amendment
implementation.
We
agree
with
commenters
that
we
should
not
require
Plan
amendment
before
material
changes
are
made.
Therefore,
we
have
revised
the
proposed
rule
to
provide
a
maximum
of
six
months
for
Plan
amendment,
and
a
maximum
of
six
more
months
for
amendment
implementation.
This
is
the
current
standard.
We
note
that
§112.3(
f)
allows
the
RA
to
authorize
an
extension
of
time
to
prepare
and
implement
an
amendment
under
certain
circumstances.

When
amendment
is
necessary.
We
agree
with
the
commenter
who
suggested
that
we
maintain
the
current
standard
for
amendments,
i.
e.,
when
there
is
a
change
that
materially
affects
the
facility's
potential
to
discharge
oil.
This
position
accords
with
our
stance
on
when
Plans
should
be
prepared
and
implemented.
See
§112.3.
The
other
suggested
standards
too
narrowly
limit
the
changes
which
would
trigger
Plan
amendment.
We
believe
that
an
amendment
is
necessary
when
a
facility
change
results
in
a
decrease
in
the
volume
stored
or
a
decrease
in
the
potential
for
an
oil
spill
because
EPA
needs
this
information
to
determine
compliance
with
the
rule.
For
example,
the
amount
of
secondary
containment
required
depends
on
the
storage
capacity
of
a
container.
Decreases
might
also
affect
the
way
a
facility
plans
emergency
response
measures
and
training
procedures.
A
lesser
capacity
might
require
different
response
measures
than
a
larger
capacity.
The
training
of
employees
might
be
affected
because
the
operation
and
maintenance
of
the
facility
might
be
affected
by
a
lesser
storage
capacity.
142
Likewise,
a
standard
requiring
amendment
"when
there
are
indicia
of
problems"
is
too
vague
and
leaves
problems
unaddressed
which
may
result
in
a
discharge
as
described
in
§112.1(
b).
A
standard
requiring
an
amendment
only
when
the
change
would
cause
the
spill
potential
to
exceed
the
Plan's
capabilities
(because
day­
to­
day
changes
do
not
affect
the
worst
case
spill)
would
have
the
effect
of
leaving
no
documentation
of
amendments
which
might
affect
discharges
which
do
not
reach
the
standard
of
"worst
case
spill."
While
we
encourage
facilities
to
incorporate
new
procedures
into
Plans
which
would
help
to
prevent
discharges,
amendments
are
still
necessary
when
material
changes
are
made
to
document
those
new
procedures,
and
thus
facilitate
the
enforcement
of
the
rule's
requirements.
We
disagree
that
a
small
facility
should
be
exempt
from
making
amendments
for
material
changes.
Amendments
may
be
necessary
at
large
or
small
facilities
alike
to
prevent
discharges
after
material
changes.

Tanks
over
5,
000
gallons.
We
decline
to
apply
the
§112.5(
a)
material
change
requirement
only
to
tanks
or
containers
over
5,
000
gallons.
A
small
container
may
be
the
source
of
a
discharge.
Therefore,
preventive
measures
are
necessary
for
such
containers,
including
Plan
amendments.

VIII
­
B:
Periodic
review
of
plans
­
§112.5(
b)

Background:
Under
§112.5(
b)
of
the
current
rule,
the
owner
or
operator
of
a
facility
subject
to
§112.3(
a),
(b),
or
(c)
must
complete
a
review
and
evaluation
of
his
SPCC
Plan
at
least
once
every
three
years
from
the
date
his
facility
becomes
subject
to
part
112.
He
must
amend
the
SPCC
Plan
within
six
months
of
the
review
to
include
more
effective
prevention
and
control
technology
if
such
technology
will
significantly
reduce
the
likelihood
of
a
spill
event
from
the
facility,
and
if
such
technology
has
been
fieldproven
at
the
time
of
the
review.

In
the
1991
proposal,
we
requested
comments
on
whether
a
facility
owner
or
operator
should
affix
a
signed
and
dated
statement
to
the
SPCC
Plan
indicating
that
the
triennial
review
has
taken
place
and
whether
the
Plan
requires
amendment.
We
did
not
propose
a
change
in
rule
text
in
1991,
but
in
1997
we
proposed
to
require
the
owner
or
operator
to
certify
completion
of
the
review.
We
also
proposed
in
1997
to
change
the
three­
year
review
cycle
to
a
five­
year
review
cycle.
We
address
the
comments
received
on
the
1997
proposal
in
the
Response
to
Comments
document
for
the
1997
proposal.

Comments:
Support
for
proposal.
"Without
this
requirement,
we
feel
that
many
companies
would
claim
to
have
reviewed
their
plan
when
they
had
not."
(10,
27,
62,
74,
95,
L17).

Opposition
to
proposal.
"The
requirement
would
be
extremely
costly
and
unnecessary.
(28,
31,
37,
54,
83,
86,
101,
143,
160)
If
a
Plan
is
submitted
and
approved,
we
should
require
no
further
changes.
(28,
101)
143
Case­
by­
case
basis.
"The
requirement
proposed
at
subsection
(b)
should
be
deleted.
If
necessary,
they
could
be
applied
on
a
case
by
case
basis
to
facilities
determined
by
the
Agency
to
present
a
high
risk
of
catastrophic
failure.
In
no
case
should
they
be
applied
to
all
facilities
subject
to
SPCC
Plan
requirements."
(31,
86,
160)

Lack
of
oversight.
We
cited
no
evidence
of
an
increased
number
of
spills
from
SPCC­
regulated
facilities
due
to
a
lack
of
managerial
oversight.
There
is
no
evidence
that
more
managerial
oversight
would
improve
the
quality
and
effectiveness
of
an
SPCC
Plan.
(31,
34)
This
provision
would
be
redundant
and
would
result
in
an
unnecessary
paperwork
increase.
(25,
155,
190,
192)

Owner/
operator
discretion.
"This
rule
should
remain
flexible
and
be
implemented
at
the
discretion
of
the
facility
owner/
operator.
If
EPA
believes
that
a
technology
should
be
adopted
by
industry,
it
should
announce
it
in
the
Federal
Register,
hold
a
public
hearing,
and
consider
all
the
arguments
for
and
against
imposing
the
requirement."
(143)

PE
input.
"Accordingly,
IFTOA
recommends
that
amendments
to
the
SPCC
Plan
be
made
following
triennial
review
and
evaluation
if
the
Registered
PE,
after
his
review
of
the
new
technology
and
a
cost
benefit
analysis,
informs
the
company
that
changes
should
be
made.
Thus,
good
engineering
practices
rather
than
`speculation'
about
new
technology
will
be
the
underlying
basis
for
any
amendment."
(54)

Production
facilities.
"Applying
such
a
requirement
to
typical
oil
and
gas
production
operations
could
cause
premature
abandonment
of
valuable
reserves
by
imposing
potentially
high
investment
requirements
on
facilities
which
by
nature
produce
a
decreasing
revenue
stream
over
time.
Given
the
low
risk
from
the
typical
oil
and
gas
production
operation,
such
a
requirement
is
unjustified."
(31,
86)

Field­
proven
technology.
We
should
clarify
the
term
field­
proven
technology.
(35,
27)

Who
performs
the
review.
"Professional
Engineers,
not
facility
owners
and
operators,
should
complete
the
three­
year
SPCC
Plan
review
and
evaluation
to
determine
if
the
facility
is
in
compliance
with
relative
industry
standards
as
well
as
federal
and
state
rules
and
regulations.
Most
owners,
if
left
to
their
own
discretion,
will
not
voluntarily
say
or
realize
that
their
facility
is
not
in
compliance.
This
puts
a
greater
burden
on
the
regulating
community
to
verify
facility
compliance."
(111)

Documentation
of
review.
We
should
require
owners
or
operators
to
affix
a
signed
and
dated
statement
to
the
Plan
stating
that
the
review
has
taken
place,
and
indicating
whether
an
amendment
to
the
Plan
is
necessary.
(121)
144
Response:
Support
for
proposal.
We
appreciate
commenter
support.
We
note
that
we
do
not
routinely
require
an
owner
or
operator
to
submit
the
Plan
nor
do
we
approve
Plans.
We
decline
to
grant
the
owner
or
operator
discretion
to
decide
whether
or
not
to
conduct
the
review.
This
provision
is
important
for
all
regulated
facilities,
large
and
small,
because
modern
technology
is
dynamic,
and
a
responsible
owner
or
operator
should
periodically
assess
whether
the
latest
field­
proven
technological
advances
could
decrease
the
facility's
oil
spill
potential.

Documentation
of
review.
We
agree
that
we
should
require
an
owner
or
operator
to
affix
a
signed
and
dated
statement
to
the
Plan
stating
that
the
review
has
taken
place,
and
indicating
whether
an
amendment
to
the
Plan
is
necessary.
See
the
1997
Response
to
Comments
Document
for
further
discussion
of
this
issue.

Time
line
for
amendment
implementation.
We
agree
with
commenters
(see
comments
on
proposed
§112.5(
a))
that
the
preparation
and
implementation
of
Plan
amendments
require
more
time
than
proposed.
The
same
rationale
applies
to
the
preparation
and
implementation
of
amendments
required
due
to
five­
year
reviews.
Therefore,
we
will
require
adherence
to
the
time
lines
laid
down
in
§112.5(
b)
for
amendments.
Currently,
§112.5(
b)
requires
that
Plan
amendments
be
prepared
within
six
months.
It
is
silent
as
to
timelines
for
implementation.
Therefore,
we
have
revised
the
rule
to
clarify
that
amendments
must
be
implemented
as
soon
as
possible,
but
within
the
next
six
months.
This
is
the
current
standard
for
implementation
of
certain
other
amendments.
See,
for
example,
§§
112.3(
a)
and
112.4(
e).
We
note
that
§112.3(
f)
allows
you
to
request
an
extension
of
time
to
prepare
and
implement
an
amendment.

Field­
proven
technology.
Field­
proven
technology
means
that
the
technology
has
been
validated
in
a
setting
typical
of
everyday
use.

VIII
­
C:
PE
certification
of
technical
amendments
­
§112.5(
c)

Background:
Under
§112.5(
c)
of
the
current
rule,
a
Professional
Engineer
(PE)
must
certify
any
amendment
to
an
SPCC
Plan
in
accordance
with
§112.3(
d).
We
proposed
to
modify
this
provision
in
1991
to
require
that
a
PE
must
certify
all
amendments
to
the
Plan
except
for
the
contact
list
required
by
§112.7(
a)(
3)(
ix).

Comments:
Support
for
proposal.
Allowing
changes
to
the
contact
list
without
PE
certification
makes
sense
and
results
in
cost
savings
for
facilities.
(23,
27,
88,
103)

PE
certification.
The
§112.5(
c)
requirement
to
certify
every
amendment
by
a
PE
poses
too
great
a
cost,
and
the
benefits
do
not
justify
the
costs.
(28,
69,
101,
165,
L15)

Increase
in
discharge
potential.
We
should
require
PE
certification
only
for
changes
that
increase
a
facility's
potential
to
discharge
oil.
(95,
102,
167,
L12)
145
Changes
"affecting"
discharge
potential.
We
should
require
PE
certification
only
for
changes
that
affect
a
facility's
potential
to
discharge
oil.
(33,
48,
67,
173,
175,
L7)

"Modify"
physical
characteristics.
We
should
require
PE
certification
only
for
facility
changes
that
modify
the
physical
characteristics
and
engineering
features
described
in
the
Plan.
(115)

Substantive
changes,
three­
year
review.
We
should
require
Plan
recertification
only
if
the
owner
or
operator
makes
substantive
changes
to
the
Plan
or
is
engaged
in
the
Plan
three­
year
review.
(75)

PE
certification
­
technical
amendments.
Adopting
the
proposed
requirement
would
result
in
less
frequent
Plan
revision.
(62)
Decommissioning
tanks,
minor
modifications
to
piping
systems,
and
changes
in
operations
or
maintenance
procedures
at
a
facility
should
not
require
Plan
recertification.
(113,
165,
L15)
"Section
112.5(
c)
should
be
revised
to
allow
some
facility
changes,
including
those
changes
requiring
Plan
amendments
[see
112.5(
a)]
without
the
requirement
to
recertify
the
Plan."
(91,
133,
182)

PE
Certification
­
Plan
or
amendment.
We
should
clarify
whether
a
PE
must
recertify
the
Plan
or
simply
certify
Plan
amendments.
(76)

Alternate
certification
suggested.
We
should
revise
§112.5(
c)
to
allow
either
a
geologist
or
hydrologist
with
a
degree
and
five
years
experience;
an
engineer
with
a
degree
and
five
years
experience;
or
a
registered
PE
to
certify
Plan
amendments.
(70)

Response:
Support
for
proposal.
We
appreciate
commenter
support.
However,
we
have
reduced
the
regulatory
and
information
collection
burden
by
permitting
a
five­
year
review
interval,
with
the
same
technological
conditions.
We
have
also
adopted
the
requirement
proposed
in
1997
that
the
owner
or
operator
certify
completion
of
the
review.

PE
certification.
It
is
the
responsibility
of
the
owner
or
operator
to
document
completion
of
review,
but
completion
of
review
and
Plan
amendment
are
two
different
processes.
PE
certification
is
not
necessary
unless
the
Plan
is
amended.

PE
certification
­
technical
amendments.
We
believe
that
PE
certification
is
necessary
for
any
technical
amendment
that
requires
the
application
of
good
engineering
practice.
We
believe
that
the
value
of
such
certification
justifies
the
cost,
in
that
good
engineering
practice
is
essential
to
help
prevent
discharges.
Therefore,
we
have
amended
the
rule
to
require
PE
certification
for
technical
changes
only.
Non­
technical
changes
not
requiring
the
exercise
of
good
engineering
practice
do
not
require
PE
certification.
Such
non­
technical
changes
include
but
are
not
limited
to
items
as:
changes
to
the
contact
list;
more
stringent
requirements
for
stormwater
discharges
to
comply
with
NPDES
rules;
phone
numbers;
product
changes
if
the
new
product
is
146
compatible
with
conditions
in
the
existing
tank
and
secondary
containment;
and,
any
other
changes
which
do
not
materially
affect
the
facility's
potential
to
discharge
oil.
If
the
owner
or
operator
is
not
sure
whether
the
change
is
technical
or
non­
technical,
he
should
have
it
certified.

PE
Certification
­
Plan
or
amendment.
The
PE
must
only
certify
any
amendments
made
when
the
owner
or
operator
amends
the
Plan
pursuant
to
§112.5(
c),
not
the
entire
Plan.

Alternate
certification
suggested.
We
disagree
that
anyone
other
than
a
PE
should
certify
a
Plan
or
an
amendment.
See
the
discussion
under
section
IV.
D
and
under
section
V
(relating
to
§112.3(
d))
of
today's
preamble,
and
section
VI.
C
of
this
document.

PE
certification
­
standard
for
amendment.
We
disagree
that
we
should
require
PE
certification
only
for
changes
that
would
increase
a
facility's
potential
to
discharge
oil.
We
believe
that
an
amendment
is
necessary
when
a
facility
change
results
in
a
decrease
in
the
volume
stored
or
a
decrease
in
the
potential
for
an
oil
spill
because
EPA
needs
this
information
to
determine
compliance
with
the
rule.
For
example,
the
amount
of
secondary
containment
required
depends
on
the
storage
capacity
of
a
container.
147
Category
IX:
Civil
Penalties
­
§112.6
(Rescinded)

Background:
Section
112.6
of
the
original
SPCC
rule
set
out
the
civil
penalties
associated
with
violating
various
part
112
provisions.
In
1991,
we
proposed
a
more
extensive
list
of
provisions,
the
violation
of
which
would
subject
an
owner
or
operator
to
these
penalties.

Comments:
Federal
agencies
are
subject
to
civil
penalties
under
the
CWA.
(42)
Criminal
penalties
associated
with
negligent
violations
are
unreasonable
because
one
drop
of
oil
is
a
harmful
quantity.
(62)
The
civil
penalties
stated
in
§112.6
are
excessive
–
especially
for
small
oil
facilities.
The
penalty
amounts
might
exceed
a
small
operator's
net
worth.
(28,
101)
The
terms
substantial
harm
and
sensitive
(environments)
are
vague,
and
owners
or
operators
may
face
law
suits
as
a
consequence
of
various
interpretations
of
these
terms.
(149)
The
amendment
is
unnecessary
because
current
penalty
provisions
already
encourage
adequate
containment
and
spill
prevention
measures.
(192)

Response:
We
have
not
adopted
the
proposal
that
would
expand
the
list
of
part
112
provisions
and
the
civil
penalties
associated
with
violating
those
provisions
because
we
rescinded
§112.6
in
1996.
We
rescinded
§112.6
because
that
penalty
provision
no
longer
accurately
reflected
the
penalties
provided
for
under
section
311(
b)
of
the
Act,
as
amended
by
OPA.
March
11,
1996,
61
FR
9646.

EPA
disagrees
that
Federal
agencies
are
subject
to
penalties
or
fines
under
the
CWA
because
the
Federal
government
is
not
a
"person"
under
sections
311(
a)(
7)
or
502
of
the
CWA.
Only
"persons"
(including
owners
or
operators
and
persons
in
charge)
are
subject
to
such
penalties.
Therefore,
although
Federal
agencies
must
comply
with
requirements
of
a
CWA
section
311
rule
in
accordance
with
CWA
section
313,
they
are
not
subject
to
civil
or
criminal
penalties
or
fines.
See
U.
S.
Department
of
Energy
v.
Ohio,
503
U.
S.
607,
618
(1992)
(because
the
CWA
does
not
define
"person"
to
include
the
United
States,
the
civil
penalty
provisions
are
not
applicable.)
148
Category
X:
General
substantive
requirements
­
§112.7
X
­
A:
Reorganization
of
the
regulation
­
§112.7(
a)
and
(a)(
1)
(See
also
section
V
14

Background:
In
1991,
we
proposed
to
separate
§112.7
into
five
sections
(§§
112.7,
112.
8,
112.
9,
112.
10,
and
112.
11),
based
on
facility
type
to
promote
ease
in
using
and
understanding
the
regulation.

Proposed
§112.7
provided
general
requirements
for
preparing
SPCC
Plans.
The
new
sections
addressed
detailed
Plan
requirements
for
onshore
facilities
(excluding
production
facilities)
(§
112.
8);
onshore
production
facilities
(§
112.
9);
onshore
oil
drilling
and
workover
facilities
(§
112.
10);
and
offshore
oil
drilling,
production,
and
workover
facilities
(§
112.
11).
In
reorganizing
part
112
into
sections,
we
intended
no
substantive
change.

In
1995,
Congress
enacted
Public
Law
104­
55,
the
Edible
Oil
Regulatory
Reform
Act
(EORRA).
That
statute
mandates
that
most
Federal
agencies
differentiate
between
and
establish
separate
classes
for
various
types
of
oils.
In
response
to
EORRA,
we
have
divided
part
112
by
subparts
for
the
various
classes
of
oil
listed
in
that
Act.
Subpart
A
consists
of
an
applicability
section,
definitions,
and
general
requirements
for
all
facilities.
Subpart
B
is
for
petroleum
oils
and
non­
petroleum
oils,
except
for
animal
fats
and
vegetable
oils.
Subpart
C
is
for
animal
fats
and
oils
and
greases,
and
fish
and
marine
mammal
oils;
and
for
oils
of
vegetable
origin,
including
oils
from
seeds,
nuts,
fruits,
and
kernels.
Subpart
D
is
for
response
requirements.

Sequence
of
Plan.
In
1991,
in
§112.7(
a)(
1),
we
reproposed
the
requirement
in
the
current
§112.7
introductory
paragraph
that
the
Plan
must
follow
the
sequence
outlined
in
§112.
7,
and
include
a
discussion
of
how
the
facility
conforms
with
the
requirements
listed
in
the
rule.
We
modified
the
1991
proposal
in
1997
to
allow
alternate
formats.
See
the
preamble
to
today's
rule
and
the
1997
Comment
Response
Document.
In
the
final
rule,
the
reference
to
sequence
§112.7(
a)(
1)
was
relocated
to
the
introductory
paragraph
of
§112.7(
a).

Current
§112.7(
a)
­
pre­
1974
spills.
Because
the
information
was
no
longer
relevant,
in
1991,
we
proposed
deletion
of
§112.7(
a),
which
required
a
description
of
certain
discharges
to
navigable
waters
or
adjoining
shorelines
that
occurred
prior
to
the
effective
date
of
the
rule
in
1974.

Comments:
Current
§112.7(
a)
­
pre­
1974
spills.
"This
proposal
to
eliminate
the
inventory
requirement
is
appropriate
since
records
of
pre­
1973
discharges
often
do
not
exist,
and
even
if
these
records
are
available,
they
provide
no
useful
environmental
protection
benefit
to
current
mining
operations
or
to
EPA
and
create
a
serious
administrative
and
investigative
burden."
(25,
35,
114)
149
Management
approval
of
Plan.
We
were
unclear
when
we
proposed
in
§112.7(
a)(
1)
that
"the
Plan
shall
have
the
full
approval
of
management
at
a
level
with
authority
to
commit
the
necessary
resources
to
fully
implement
the
Plan."
We
should
clarify
whether
we
require
any
documentation
for
this
approval
and
whether
there
are
any
limitations
on
who
we
consider
"management."
(115)

Sequence
of
Plan.

§112.7(
a)(
3).
The
sequence
should
be
as
outlined
in
§112.7(
a)(
3).
It
"would
be
most
helpful
to
have
the
outline
clearly
stated
by
a
paragraph
immediately
following
Section
112.7(
a)(
1)."
(121,
L33)

Clarification
needed.
"The
proposed
rule
is
written
in
such
a
way
that
is
unclear
as
to
the
proper
format
of
the
plan.
...
We
recommend
that
a
guidance
document
containing
examples
of
acceptable
SPCC
Plans
be
made
available
before
or
at
the
time
of
promulgation
of
the
final
rule."
(79)

No
set
sequence.
"The
Section
112.7(
a)(
1)
requirement
that
all
Plans
follow
a
specific
`sequence'
should
be
deleted.
To
require
that
all
Plans
to
follow
a
predesignated
sequence
which
may
or
may
not
be
the
most
appropriate
or
useful
for
the
facility
personnel
that
must
carry
out
the
Plan
is
not
in
the
best
interest
of
protecting
navigable
waters.
The
Plan
developers
should
be
allowed
the
freedom
to
organize
the
Plan
to
suit
the
facility
needs
relative
to
SPCC
requirements
and
to
incorporate
elements
required
by
other
regulations
for
the
development
of
such
emergency
prevention
and
response
plans.
During
an
actual
emergency,
a
consolidated
Plan
greatly
enhances
the
effectiveness
of
the
response."
(67,
95,
102,
175)

Recommendation
instead.
We
should
change
the
requirement
to
a
recommendation,
because
a
requirement
provides
no
pollution
prevention
benefit.
(95)

Support
for
reorganization.
Support
for
our
decision
to
separate
§112.7
into
five
sections
based
on
facility
type.
EPA
recognized
the
differences
in
facility
design
and
sought
to
provide
the
regulated
community
with
greater
certainty
about
its
legal
obligations.
(27,
53,
L4)

Opposition
to
reorganization.
We
would
increase
reporting
requirements;
replace
an
existing,
satisfactory
compliance
program
with
one
that
asserts
additional
command
and
control
authority;
expand
regulatory
jurisdiction;
and
increase
compliance
costs
to
industry
and
society,
while
providing
no
incremental
environmental
protection
benefit.
(35)
We
are
creating
an
unnecessary
burden
by
restructuring
the
regulation.
(16,
79)

Response:
We
have
reorganized
the
rule
text,
placing
§§
112.8
through
112.11
into
Subpart
B.
We
have
changed
the
section
numbers
of
the
provisions,
but
have
not
thereby
imposed
new
requirements,
nor
expanded
our
jurisdiction
or
authority.
150
Current
§112.7(
a)
­
pre­
1974
spills.
In
1991,
we
proposed
to
delete
§112.7(
a),
which
required
a
description
of
certain
discharges
to
navigable
waters
or
adjoining
shorelines
which
occurred
prior
to
the
effective
date
of
the
rule
in
1974,
because
that
information
was
no
longer
relevant.
56
FR
54620.
We
received
several
comments
supporting
the
proposed
deletion
of
this
provision,
and
have
deleted
it.

Management
approval
of
Plan.
The
owner
or
operator
of
the
facility,
or
a
person
at
a
management
level
with
sufficient
authority
to
commit
the
necessary
resources,
must
implement
the
Plan.
That
person
may
vary
from
facility
to
facility,
therefore
we
cannot
specify
a
certain
title.
Documentation
of
this
authority
is
shown
by
signature
on
the
Plan.

Sequence
of
Plan.
In
the
1997
proposal,
we
withdrew
the1991
proposal
that
would
have
required
a
Plan
to
follow
the
sequence
outlined
in
§112.7.
See
the
Response
to
Comments
Document
for
the
1997
proposal
for
the
comments
and
responses
to
that
proposal.

X
­
B:
Deviations
­
§112.7(
a)(
2)

Background:
In
1991,
we
proposed
to
amend
§112.7(
a)(
2)
to
permit
the
use
of
methods
not
expressly
called
for
in
proposed
§112.7(
c)
and
§§
112.8
through
112.11,
as
long
as
these
practices
provided
environmental
protection
equivalent
to
part
112
provisions.
In
the
1991
proposal,
we
said
that
we
would
retain
our
discretion
to
determine
that
an
alternative
method
did
not
provide
equivalent
protection.

Comments:
Support
for
proposal.
This
provision
would
encourage
development
of
innovative
spill
prevention
and
control
measures.
(72,
164,
190,
L29)

Opposition
to
proposal.

Electrical
equipment.
Requirements
other
than
the
secondary
containment
and
integrity
testing
requirements
­­
may
be
impracticable
for
electrical
equipment,
including
the
proposed
§112.8
drainage
requirements
and
the
requirement
to
provide
detailed
site
plans,
flow
paths,
and
failure
analyses.
(125)

RA
oversight.

"Apparent"
equivalency.
References
the
provision
in
proposed
§112.8(
b)(
3)
that
"drainage
systems
from
undiked
areas
`shall'
flow
into
ponds,
lagoons,
or
catchment
basins"
as
"one
example
of
a
requirement
that
does
not
lend
itself
to
comparison
with
an
`equivalent'
alternative."
Equivalency
may
not
be
apparent
in
some
instances
from
the
physical
structure
of
the
alternative
measure.
"...(
I)
n
practice
it
will
be
impossible
to
prove
equivalency
to
the
satisfaction
of
EPA
enforcement
officials."
(125,
146,
170,
189,
L27)
151
EPA
evaluation.
"An
alternative
is
to
require
that
Plans
containing
such
a
technical
waiver
be
reviewed
by
US
EPA
in
order
to
determine
if
such
a
method
is
applicable
to
the
use
intended."
Whether
an
alternate
measure
provides
"equivalent
alternate
protection"
depends
on
the
facility
and
the
location
within
the
facility.
(76)

Inspectors
and
equivalency.
The
"check­
lists
of
requirements"
that
inspectors
often
carry
do
not
include
"equivalent
environmental
protection."
Because
we
did
not
provide
guidance
on
what
constitutes
an
equivalent
measure,
the
inspector
may
be
"unfamiliar
with
the
unique
operational
characteristics
of
utility
equipment."
(125)

Mathemetical
equivalency.
We
should
clarify
that
§112.7(
a)(
2)
does
not
require
mathematical
equivalency
of
every
requirement,
but
rather,
the
"achievement
of
substantially
the
same
level
of
overall
protection
from
the
risk
of
discharge
at
the
facility
as
the
specific
requirement
seeks
to
achieve."
It
would
be
impossible
to
prove
equivalency
to
the
satisfaction
of
inspectors.
(125,
170)

No
RA
oversight.
Would
delete
provision
allowing
RA
to
overrule
alternative
measures
selected
under
this
section.
(121)

Response:
Support
for
proposal.
We
appreciate
commenter
support.

Applicability.
We
generally
agree
with
the
commenter
that
an
owner
or
operator
should
have
flexibility
to
substitute
alternate
measures
providing
equivalent
environmental
protection
in
place
of
express
requirements.
Therefore,
we
have
expanded
the
proposal
to
allow
deviations
from
the
requirements
in
§112.7(
g),
(h)(
2)
and
(3),
or
(i),
as
well
as
subparts
B,
and
C,
except
for
the
listed
secondary
containment
provisions
in
§112.7
and
subparts
B
and
C.
The
proposed
rule
already
included
possible
deviations
for
any
of
the
requirements
listed
in
§§
112.7(
c),
112.8,
112.9,
112.10,
and
112.11.
We
have
expanded
this
possibility
of
deviation
to
include
the
new
subparts
we
have
added
for
various
classes
of
oils.
We
take
this
step
because
we
believe
that
the
application
of
good
engineering
practice
requires
the
flexibility
to
use
alternative
measures
when
such
measures
offer
equivalent
environmental
protection.
This
provision
may
be
especially
important
in
differentiating
between
requirements
for
facilities
storing,
processing,
or
otherwise
using
various
types
of
oil.

A
deviation
may
be
used
whenever
an
owner
or
operator
can
explain
his
reasons
for
nonconformance,
and
provide
equivalent
environmental
protection.
Possible
rationales
for
a
deviation
include
when
the
owner
or
operator
can
show
that
the
particular
requirement
is
inappropriate
for
the
facility
because
of
good
engineering
practice
considerations
or
other
reasons,
and
that
he
can
achieve
equivalent
environmental
protection
in
an
alternate
manner.
For
example,
a
requirement
that
may
be
essential
for
a
facility
storing
gasoline
may
be
inappropriate
for
a
facility
storing
asphalt;
or,
the
owner
or
operator
may
be
able
to
implement
equivalent
environmental
protection
through
an
alternate
technology.
An
owner
or
operator
may
consider
cost
as
one
of
the
152
factors
in
deciding
whether
to
deviate
from
a
particular
requirement,
but
the
alternate
provided
must
achieve
environmental
protection
equivalent
to
the
required
measure.
The
owner
or
operator
must
ensure
that
the
design
of
any
alternate
device
used
as
a
deviation
is
adequate
for
the
facility,
and
that
the
alternate
device
is
adequately
maintained.
In
all
cases,
the
owner
or
operator
must
explain
in
the
Plan
his
reason
for
nonconformance.
We
wish
to
be
clear
that
we
do
not
intend
this
deviation
provision
to
be
used
as
a
means
to
avoid
compliance
with
the
rule
or
simply
as
an
excuse
for
not
meeting
requirements
the
owner
or
operator
believes
are
too
costly.
The
alternate
measure
chosen
must
represent
good
engineering
practice
and
must
achieve
environmental
protection
equivalent
to
the
rule
requirement.
Technical
deviations,
like
other
substantive
technical
portions
of
the
Plan
requiring
the
application
of
engineering
judgment,
are
subject
to
PE
certification.

In
the
preamble
to
the
1991
proposal
(at
56
FR
54614),
we
noted
that
"...
aboveground
storage
tanks
without
secondary
containment
pose
a
particularly
significant
threat
to
the
environment.
The
Phase
One
modifications
would
retain
the
current
requirement
for
facility
owners
or
operators
who
are
unable
to
provide
certain
structures
or
equipment
for
oil
spill
prevention,
including
secondary
containment,
to
prepare
facilityspecific
oil
spill
contingency
plans
in
lieu
of
the
prevention
systems."
In
keeping
with
this
position,
we
have
deleted
the
proposed
deviation
in
§112.7(
a)(
2)
for
the
secondary
containment
requirements
in
§§
112.7(
c)
and
(h)(
1);
and
for
proposed
§§
112.8(
c)(
2),
112.8(
c)(
11),
112.9(
c)(
2),
112.10(
c);
as
well
as
for
the
new
sections
which
are
the
counterparts
of
the
proposed
sections,
i.
e.,
§§
112.12(
c)(
2),
112.12(
c)(
11),
112.13(
c)(
2),
and
112.14(
c),
because
a
more
appropriate
deviation
provision
already
exists
in
§112.
7(
d).
Section
112.
7(
d)
contains
the
measures
which
a
facility
owner
or
operator
must
undertake
when
the
secondary
containment
required
by
§112.7(
c)
or
(h)(
1),
or
the
secondary
containment
provisions
in
the
rule
found
at
§§
112.8(
c)(
2),
112.8(
c)(
11),
112.9(
c)(
2),
112.10(
c),
112.12(
c)(
2),
112.12(
c)(
11),
112.13(
c)(
2),
and
112.14(
c),
are
not
practicable.
Those
measures
are
expressly
tailored
to
address
the
lack
of
secondary
containment
at
a
facility.
They
include
requirements
to:
explain
why
secondary
containment
is
not
practicable;
conduct
periodic
integrity
testing
of
bulk
storage
containers;
conduct
periodic
integrity
and
leak
testing
of
valves
and
piping;
provide
in
the
Plan
a
contingency
plan
following
the
provisions
of
40
CFR
part
109;
and,
provide
a
written
commitment
of
manpower,
equipment,
and
materials
to
expeditiously
control
and
remove
any
quantity
of
oil
discharged
that
may
be
harmful.
Therefore,
when
an
owner
or
operator
seeks
to
deviate
from
secondary
containment
requirements,
§112.7(
d)
will
be
the
applicable
"deviation"
provision,
not
§112.7(
a)(
2).

Deviation
submission.
We
agree
with
the
commenter
that
submission
of
a
deviation
to
the
Regional
Administrator
is
not
necessary
and
have
deleted
the
proposed
requirement.
We
take
this
step
because
we
believe
that
the
requirement
for
good
engineering
practice
and
current
inspection
and
reporting
procedures
(for
example,
§112.
4(
a)),
followed
by
the
possibility
of
required
amendments,
are
adequate
to
review
Plans
and
to
detect
the
flaws
in
them.
Upon
submission
of
required
information,
or
upon
on­
site
review
of
a
Plan,
if
the
RA
decides
that
any
portion
of
a
Plan
is
153
inadequate,
he
may
require
an
amendment.
See
§112.4(
d).
If
you
disagree
with
his
determination
regarding
an
amendment,
you
may
appeal.
See
§112.4(
e).

RA
oversight.
Once
an
RA
becomes
aware
of
a
facility's
SPCC
Plan
as
a
result
on
an
on­
site
inspection
or
the
submission
of
required
information,
he
is
to
follow
the
principles
of
good
engineering
practice
and
not
overrule
a
deviation
unless
it
is
clear
that
such
deviation
fails
to
afford
equivalent
environmental
protection.
This
does
not
mean
that
the
deviation
must
achieve
"mathematical
equivalency,"
as
one
commenter
pointed
out.
But
it
does
mean
equivalent
protection
of
the
environment.
We
encourage
innovative
techniques,
but
such
techniques
must
also
protect
the
environment.
We
also
believe
that
in
general
PEs
will
seek
to
protect
themselves
from
liability
by
only
certifying
measures
that
do
provide
equivalent
environmental
protection.
But
the
RA
must
still
retain
the
authority
to
require
amendments
for
deviations,
as
he
can
with
other
parts
of
the
Plan
certified
by
a
PE.

Not
covered
under
the
deviation
provision.
Deviations
under
§112.7(
a)(
2)
are
not
allowed
for
the
general
and
specific
secondary
containment
provisions
listed
above
because
§112.7(
d)
contains
the
necessary
requirements
when
you
find
that
secondary
containment
is
not
practicable.
We
have
amended
both
this
paragraph
and
§112.7(
d)
to
clarify
this.
Instead,
the
contingency
planning
and
other
requirements
in
§112.7(
d)
apply.
Deviations
are
also
not
available
for
the
general
recordkeeping
and
training
provisions
in
§112.7,
as
these
requirements
are
meant
to
apply
to
all
facilities,
or
for
the
provisions
of
§112.7(
f)
and
(j).
We
already
provide
flexibility
in
the
manner
of
record
keeping
by
allowing
the
use
of
ordinary
and
customary
business
records.
Training
and
a
discussion
of
compliance
with
more
stringent
State
rules
are
essential
for
all
facilities.
Therefore,
we
do
not
allow
deviations
for
these
measures.

X
­
C:
Plan
information
­
§112.7(
a)
and
(b)

Background:
In
1991,
in
§112.7(
a)(
1),
we
reproposed
the
requirement
in
the
current
§112.7
introductory
paragraph
that
the
Plan
must
follow
the
sequence
outlined
in
§112.
7,
and
include
a
discussion
of
how
the
facility
conforms
with
the
requirements
listed
in
the
rule.

In
proposed
§112.7(
a)(
3)(
i)­(
ix),
we
clarified
which
facility
characteristics
which
the
owner
or
operator
must
describe
in
the
Plan,
including
unit­
by­
unit
storage
capacity;
type
and
quantity
of
oil
stored;
estimates
of
quantity
of
oils
potentially
discharged;
possible
spill
pathways;
spill
prevention
measures;
spill
control
measures;
spill
countermeasures;
provisions
for
disposal
of
recovered
materials;
and
a
contact
list
with
appropriate
phone
numbers.
We
also
proposed
a
requirement
for
a
facility
diagram
on
which
the
location
and
contents
of
all
tanks
would
be
marked.

Under
proposed
§112.7(
a)(
4),
an
owner
or
operator
would
have
to
provide
documentation
in
the
Plan
that
would
enable
a
person
reporting
a
spill
to
provide
spillspecific
information,
including
the
exact
address
and
phone
number
of
the
facility;
the
spill
date
and
time;
the
type
of
material
spilled;
estimates
of
the
total
quantity
spilled;
154
estimates
of
the
quantity
spilled
into
navigable
water;
the
spill's
source;
a
description
of
the
affected
medium;
the
spill's
cause;
any
damages
or
injuries
caused
by
the
spill;
actions
being
used
to
stop,
remove,
and
mitigate
the
effects
of
the
discharge;
whether
an
evacuation
may
be
needed;
and
the
names
of
individuals
and/
or
organizations
who
had
also
been
contacted.

Current
§112.7(
b)
requires
that,
where
experience
indicates
a
reasonable
potential
for
equipment
failure
(e.
g.,
tank
overflow,
rupture,
or
leakage),
the
owner
or
operator
must
include
in
the
Plan
a
prediction
of
the
direction,
rate
of
flow,
and
total
quantity
of
oil
that
could
be
discharged
from
the
facility
as
a
result
of
each
major
type
of
failure.
In
§112.7(
b),
we
proposed
to
clarify
that
the
requirements
for
discharge
prediction
were
not
contingent
on
the
past
spill
experience
of
a
facility.

X­
C­
1
Facility
physical
description
and
diagram
­
§112.7(
a)(
3)

Background:
In
1991,
in
§112.7(
a)(
3),
we
proposed
to
require
that
a
Plan
include
a
facility
diagram
on
which
are
marked
the
location
and
contents
of
all
tanks.
We
also
proposed
to
require
that
an
owner
or
operator
address
in
the
Plan
the
essential
facility
characteristics
listed
in
§112.7(
a)(
3)(
i)­(
ix).

Comments:
Support
for
proposal.
"GM
supports
the
proposed
SPCC
plan
requirements
detailing
physical
attribute
of
the
facility,
such
as
capacity,
types
of
oil,
pathways,
etc."
(76,
90)

Opposition
to
proposal.
"Overall,
for
large
facilities
such
as
refineries,
the
amount
of
detail
required
in
112.7(
a)(
3)
is
unreasonable,
very
resource
intensive
to
compile
and
too
voluminous
for
Agency
staff
to
assimilate
or
evaluate.
API
believes
the
level
of
detail
required
will
add
little
value
to
the
Plan
for
large
facilities
such
as
refineries."
(67)
Contents
of
tank.
"However,
including
the
contents
of
the
tanks
on
the
diagram
is
not
practical.
First,
many
of
the
tanks
are
used
for
different
products
depending
on
seasonal
fluctuations
and
other
market
demands;
and
by
other
proposed
changes
the
plan
would
require
amendment
for
each
such
change.
Secondly,
if
there
are
more
than
just
a
handful
of
tanks,
it
is
difficult
for
a
new
visitor
to
a
facility
to
identify
which
tank
contains
products
which
are
potentially
explosive,
reactive,
corrosive,
or
otherwise
dangerous
to
emergency
spill
response."
(76,
92)

Containers
not
storing
oil.
Asks
whether
"exempt
ASTs
which
do
not
contain
oil"
should
be
marked
on
a
facility
diagram.
"It
would
seem
consistent
with
the
reasoning
for
showing
tanks
exempt
due
to
their
UST
status
(i.
e.,
emergency
response
crews
would
be
able
to
identify
oil
containing
tanks
from
those
with
other
materials.)"
(62)

Risk.
Suggests
"Alternative
wording,
such
as
`...
indicate
the
type
of
product
(crude
oil,
gasoline,
acid,
etc.)
or
other
information
as
necessary
to
expediently
evaluate
the
relative
hazards
presented'
would
be
more
appropriate.
In
addition,
155
requiring
recommending
methods
to
readily
identify
such
tanks
by
on­
tank
displays
would
be
prudent
as
well."
(76)

Facility
diagram
­
De
minimis
containers.
"112.7(
a)(
3)
Requirement
for
plan
to
describe
location
and
contents
of
all
tanks
will
be
unwieldy
if
even
very
small
containers
must
be
included.
Request
that
de
minimis
level
exemptions
be
established."
(62,
66,
125,
179,
184)

660
gallons.
"API
believes
tanks
with
less
than
capacity
of
660
gallons
should
not
be
included
on
the
facility
diagram.
These
tanks
are
excluded
from
current
SPCC
regulations
and
mandating
inclusion
of
such
tanks
would
make
the
facility
diagram
less
useful
due
to
increased
clutter.
The
cost
of
preparing
the
diagram
would
also
increase
substantially.
Furthermore
such
tanks
are
often
portable,
making
inclusion
on
a
facility
diagram
impractical."
(67)

Facility
diagram,
exempt
materials.
Asks
whether
exempt
USTs
which
do
not
contain
oil
should
be
marked
on
facility
diagrams.
"It
would
seem
consistent
with
the
reasoning
for
showing
tanks
exempt
due
to
their
UST
status
(i.
e.,
emergency
response
crews
would
be
able
to
identify
oil
containing
tanks
from
those
with
other
materials.)"
(62)
"Subjecting
otherwise
exempt
facilities
to
the
requirements
for
...
facility
diagrams
(112.7(
a)(
3))
is
unreasonable
considering
the
negligible
risk
posed
by
facilities
`not
reasonably
expected
to
discharge
oil'."
(167)

Facility
diagram
­
Transfer
stations,
connecting
pipes,
and
USTs.
We
should
require
an
owner
or
operator
to
include
in
the
Plan
a
diagram
that
shows
transfer
stations
and
connecting
pipes.
(111)

General
description
of
characteristics.

Approved
substances.
"...
BP
proposes
that
facility
storage
tank
diagrams
be
required
to
show
the
location
of
tanks
and
products
approved
to
be
stored
in
that
type
of
storage
tank
(ie.
cone
roof,
internal
or
external
floating
roof,
heated,
etc.).
A
list
of
possible
substances
(gasolines,
diesel
fuels,
residual
oils,
crude
oils,
etc.)
approved
to
be
stored
in
each
tank
or
type
of
tanks
would
be
indicated
on
the
facility
diagram
or
elsewhere
in
the
SPCC
Plan.
The
log
book
and
facility
status
board
would
then
provide
information
on
the
current
contents
of
each
tank."
(96)

Facility
based
information.
We
should
require
that
the
owner
or
operator
address
§112.7(
a)(
3)
information
"on
a
facility
basis."
"This
addition
would
clarify
the
detail
needed
for
the
Plan
and
make
it
consistent
with
the
type
of
information
required
in
the
Section
112.1(
e),
notification
requirements.
Since
storage
capacity
and
type
and
quantity
stored
in
each
tank
is
not
required
in
the
notification
requirements,
it
should
not
be
required
in
this
Plan."
(67)
156
Numbered
list.
Would
revise
§112.7(
a)(
3)
to
read:
"The
complete
plan
must
describe
the
facility's
physical
plant
and
include
a
facility
diagram,
which
must
indicate
the
location
of
all
tanks
which
shall
be
numbered,
and
it
must
be
accompanied
by
a
separate
list
of
all
the
numbered
tanks.
Those
tanks
in
oil
service
must
have
their
contents
listed
after
the
tank
number
on
the
tank
list.
A
facility
shall
maintain
an
up­
to­
date
list
of
tank
contents
as
part
of
theSPCC
plan
and
shall
furnish
it
to
EPA
upon
request.
If
tanks
have
been
removed
or
added
to
a
facility,
the
facility
must
submit
a
new
tank
diagram
and
a
list
of
numbered
tanks
which
states
the
contents
of
those
in
oil
service."
(143)

Potential
to
contaminate
navigable
water.
"EPA
should
provide
additional
clarification
that
the
required
facility
diagram
is
intended
to
be
of
a
level
of
detail
to
support
the
evaluation
of
the
potential
for
an
oil
spill
to
reach
navigable
water
and
that
a
block
diagram
of
only
those
facility
components
directly
related
to
this
risk
(e.
g.,
non­
process
equipment)
is
the
minimum
performance
standard."
(L12)

Physical
description
of
facility.
"Descriptions
of
the
physical
plant
at
a
facility
are
provided
under
many
existing
state
regulatory
schemes.
Once
again,
the
Agency
is
urged
to
develop
a
better
approach
to
working
with
State
regulatory
authorities
instead
of
redoubling
the
burden
on
the
regulated
community."
(42)

Response
requirements.
We
should
separate
response
plan
requirements
from
spill
prevention
plan
requirements,
removing
all
response
plan
requirements
from
§§
112.
7(
a)(
3)(
viii)
and
(ix),
(a)(
4),
and
(a)(
5)
and
grouping
them
in
another
section
containing
only
response
plan
requirements.
(121)

Small
facilities.

Small
production
facilities.
"OOGA
believes
that
the
facility
diagram
requirement
will
be
extremely
burdensome
to
the
small
entity
with
no
real
environmental
benefit,
and
particularly
on
the
crude
oil
production
facility
owner
who
would
be
obligated
to
construct
one
for
each
of
its
facilities.
Once
again,
for
the
reasons
set
forth
above,
OOGA
requests
that
USEPA
exempt
these
small
facilities
from
the
exception."
(28,
31,
58,
70,
86)
Such
a
requirement
would
add
two
hours
to
the
facility
review
process.
(70)
This
requirement
would
be
burdensome
and
of
limited
value
because
many
facilities
have
only
one
tank.
We
should
allow
more
time
for
an
owner
or
operator
to
comply
or
require
him
to
create
a
facility
diagram
by
the
end
of
the
three­
year
review
process.
(101)

Specific
Plan
requirements.
We
should
require
the
owner
or
operator
to
address
the
requirements,
where
applicable,
listed
in
§§
112.8,
112.9,
112.10,
and
112.11
in
the
Plan.
(121)

Response:
Support
for
proposal.
We
appreciate
the
commenter
support.
157
General
description
of
characteristics.
The
following
characteristics
must
be
described
on
a
per
container
basis:
the
storage
capacity
of
the
container,
type
of
oil
in
each
container,
and
secondary
containment
for
each
container.
The
other
characteristics
may
be
described
on
a
facility
basis.
Based
on
site
inspections
and
professional
judgment,
we
disagree
that
these
requirements
are
too
resource
intensive.
The
major
new
requirement
in
§112.7(
a)(
3)
is
the
facility
diagram.
Based
on
site
inspections
and
professional
judgment,
we
estimate
unit
costs
for
compliance
with
this
section
to
be
$33
for
a
small
facility,
$39
for
a
medium
facility,
and
$5
for
a
large
facility.
Large
facilities
are
assumed
to
already
have
a
diagram
that
may
be
attached
to
the
SPCC
Plan.
The
other
items
mentioned
in
§112.7(
a)(
3)
­
storage
capacity
of
each
container,
prevention
measures,
discharge
controls,
countermeasures,
disposal
methods,
and
the
contact
list
­
are
already
required
under
the
current
rule
or
required
by
good
engineering
practice.
As
described
in
the
Information
Collection
Request
for
this
rule,
the
cost
of
Plan
preparation
includes
these
items,
e.
g.,
field
investigations
to
understand
the
facility
design
and
to
predict
flow
paths
and
potential
harm,
regulatory
review,
and
spill
prevention
and
control
practices.

Providing
information
on
a
container­
specific
basis
helps
the
facility
to
prioritize
inspections
and
maintenance
of
containers
based
on
characteristics
such
as
age,
capacity,
or
location.
It
also
helps
inspectors
to
prioritize
inspections
of
higher­
risk
containers
at
a
facility.
Container­
specific
information
helps
an
inspector
verify
the
capacity
calculation
to
determine
whether
a
Plan
is
needed;
and,
helps
to
formulate
contingency
planning
if
such
planning
is
necessary.

Facility
diagram.
The
facility
diagram
is
important
because
it
is
used
for
effective
prevention,
planning,
management
(for
example,
inspections),
and
response
considerations
and
therefore
we
believe
that
it
must
be
part
of
the
Plan.
The
diagram
will
help
the
facility
and
emergency
response
personnel
to
plan
for
emergencies.
For
example,
the
identification
of
the
type
of
oil
in
each
container
may
help
such
personnel
determine
the
risks
when
conducting
a
response
action.
Some
oils
present
a
higher
risk
of
fire
and
explosion
than
other
than
less
flammable
oils.

Inspectors
and
personnel
new
to
the
facility
need
to
know
the
location
of
all
containers
subject
to
the
rule.
The
facility
diagram
may
also
help
first
responders
to
determine
the
pathway
of
the
flow
of
discharged
oil.
If
responders
know
possible
pathways,
they
may
be
able
to
take
measures
to
control
the
flow
of
oil.
Such
control
may
avert
damage
to
sensitive
environmental
areas;
may
protect
drinking
water
sources;
and
may
help
responders
to
prevent
discharges
to
other
conduits
leading
to
a
treatment
facility
or
navigable
waters.
Diagrams
may
assist
Federal,
State,
or
facility
personnel
to
avoid
certain
hazards
and
to
respond
differently
to
others.

The
facility
diagram
is
necessary
for
all
facilities,
large
or
small,
because
the
rationale
is
the
same
for
both.
While
some
States
may
require
a
diagram,
others
do
not.
SPCC
is
a
Federal
program
specifying
minimum
requirements,
which
the
States
may
supplement
with
their
own
more
stringent
requirements.
We
note
that
State
plans
may
be
used
as
SPCC
Plans
if
they
meet
all
Federal
requirements,
thus
avoiding
any
158
duplication
of
effort
if
the
State
facility
diagram
meets
the
requirements
of
the
Federal
one.

Facility
diagram
­
container
contents.
The
facility
diagram
must
include
all
fixed
(i.
e.,
not
mobile
or
portable)
containers
storing
55
gallons
or
more
of
oil
and
must
include
information
marking
the
contents
of
those
containers.
If
you
store
mobile
containers
in
a
certain
area,
you
must
mark
that
area
on
the
diagram.
You
may
mark
the
contents
of
each
container
either
on
the
diagram
of
the
facility,
or
on
a
separate
sheet
or
log
if
those
contents
change
on
a
frequent
basis.
Marking
containers
makes
for
more
effective
prevention,
planning,
management,
and
response.
We
disagree
that
a
list
of
products
approved
for
storage
in
the
container
is
sufficient
for
emergency
response.
While
a
document
outlining
what
materials
might
be
stored
in
a
container
is
useful,
it
does
not
say
what
is
actually
in
it
at
a
particular
time.
For
example,
a
responder
may
take
one
type
of
emergency
measure
for
one
type
of
oil,
and
another
measure
for
another
type.
As
noted
above,
oils
differ
in
their
risk
of
fire
and
explosion.
Gasoline
is
highly
flammable
and
volatile.
It
presents
the
risk
of
fire
and
inhalation
of
vapors
when
discharged.
On
the
other
hand,
motor
oil
is
not
highly
flammable,
and
there
is
no
inhalation
of
vapors
hazard
associated
with
its
discharge.

In
an
emergency,
the
responder
may
not
have
container
content
information
unless
it
is
clearly
marked
on
a
diagram,
log,
or
sheet.
For
emergency
response
purposes,
we
also
encourage,
but
do
not
require
you
to
mark
on
the
facility
diagram
containers
that
store
CWA
hazardous
substances
and
to
label
the
contents
of
those
containers.
When
the
contents
of
an
oil
container
change,
this
may
or
may
not
be
a
material
change.
See
the
discussion
on
§112.5(
a).

Facility
diagram
­
De
minimis
containers.
We
have
established
a
de
minimis
container
size
of
less
than
55
gallons.
You
do
not
have
to
include
containers
less
than
55
gallons
on
the
facility
diagram.

Facility
diagram
­
Transfer
stations,
connecting
pipes,
and
USTs.
We
agree
that
all
facility
transfer
stations
and
connecting
pipes
that
handle
oil
must
be
included
in
the
diagram,
and
have
amended
the
rule
to
that
effect.
This
inclusion
will
help
facilitate
response
by
informing
responders
of
the
location
of
this
equipment.
The
location
of
all
containers
and
connecting
pipes
that
store
oil
(other
than
de
minimis
containers)
must
be
marked,
including
USTs
and
other
containers
not
subject
to
SPCC
rules
which
are
present
at
SPCC
facilities.
Again,
this
is
necessary
to
facilitate
response
by
informing
responders
of
the
location
of
these
containers.

Physical
description
of
facility.
We
appreciate
the
commenter's
support.
In
the
final
rule,
we
have
changed
the
requirement
for
a
description
of
the
"physical
plant"
of
the
facility
to
a
description
of
the
"physical
layout"
of
the
facility.
If
the
owner
or
operator
has
provided
that
information
in
a
State
plan,
he
may
use
the
same
information
in
his
Federal
SPCC
Plan
if
the
State
requirement
is
cross­
referenced
to
the
Federal
requirement.
159
Response
requirements.
We
generally
agree
that
response
plan
requirements
should
be
separate
from
spill
prevention
plan
requirements.
However,
the
information
required
in
§112.
7(
a)
facilitates
response
to
an
emergency
and
is
necessary
for
all
facilities.
Because
a
facility
with
a
response
plan
already
documents
the
required
information,
we
have
therefore
have
exempted
any
such
facility
from
documenting
certain
information
required
for
SPCC
facilities
in
§112.
7(
a).
See,
for
example,
revised
§112.
7(
a)(
3),
(4),
and
(5).
We
disagree
that
there
is
no
need
for
§112.7(
d).
The
Minerals
Management
Service
(MMS)
is
not
responsible
for
all
offshore
oil
production
facilities.
Offshore
facilities
in
the
inland
area
fall
under
EPA
jurisdiction.
(See
EO
12777.)

Specific
Plan
requirements.
We
agree
that
an
owner
or
operator
should
address
specific
requirements
applicable
to
a
facility.
Section
112.
7(
a)(
1)
requires
a
facility
owner
or
operator
to
discuss
how
a
facility
conforms
with
part
112
requirements.
Furthermore,
the
introductions
to
§§
112.8,
112.9,
112.10,
112.11,
112.12,
112.13,
112.14,
and
112.15
reference
the
obligation
to
address
both
general
and
specific
requirements
for
the
facility.

X­
C­
2
Unit­
by­
unit
storage
capacity
­
§112.7(
a)(
3)(
i)

Background:
In
1991,
in
§112.7(
a)(
3)(
i),
we
proposed
to
require
that
an
owner
or
operator
address
unit­
by­
unit
storage
capacity
in
the
Plan.

Comments:
Minimum
size.
We
should
specify
a
minimum
size
for
units
that
owners
or
operators
must
include
in
the
Plan.
(62,
66,
79,
125,
164,
170,
184)

Small
sizes.

Opposition
to
proposal.
Requiring
owners
or
operators
to
itemize
small
units
would
be
unnecessarily
costly
and
burdensome
with
little
to
no
additional
environmental
benefit.
(62,
66,
125,
164,
170)

Alternative
sizes
suggested.

660
gallons
or
less.
Tanks
containing
greater
than
660
gallons.
(92,125,
164)

10,000
gallons
­
electrical
equipment.
Electrical
equipment
containing
greater
than
10,000
gallons
of
oil
or
dielectric
fluid.
(125,
170,
184)
If
small
pieces
of
equipment
at
electrical
substations
"catastrophically"
fail,
they
do
not
fail
synergistically
and
create
other
failures.
We
should
not
focus
on
controlling
spills
from
small
pieces
of
equipment
that
are
only
a
few
gallons
and
are
quickly
cleaned
up.
(164)

Mobile
containers.
According
to
the
proposed
requirement,
an
owner
or
operator
would
have
to
revise
the
Plan
every
time
a
drum
of
oil
was
received
or
a
piece
of
oil
containing
manufacturing
equipment
was
moved
within
the
facility.
(79)
160
"Unit."
We
did
not
define
the
term
unit,
and
we
should
clarify
whether
we
meant
tank­
by­
tank
storage
capacity.
(28,
31,
101,
165,
L15)

Response:
Minimum
size.
Under
§112.1(
d)(
5)
of
the
final
rule,
part
112
does
not
apply
to
aboveground
or
completely
buried
containers
with
an
oil
storage
capacity
of
less
than
55
gallons.
Therefore,
the
owner
or
operator
need
not
include
in
the
Plan
containers
smaller
than
55
gallons.
If
the
containers
move
frequently,
the
owner
or
operator
may
mark
the
location
of
those
containers
on
a
separate
sheet
or
log.
Movement
of
containers
may
or
may
not
be
a
material
change
in
the
Plan
requiring
amendment,
depending
on
whether
the
move
increases
or
decreases
the
risk
of
a
discharge.

"Unit."
For
clarity,
we
have
changed
the
term
unit­
by­
unit
storage
capacity
to
type
of
oil
in
each
container
and
its
storage
capacity.

X­
C­
3
Type
and
quantity
of
oil
stored
­
proposed
§112.7(
a)(
3)(
ii)

Background:
In
1991,
in
§112.7(
a)(
3)(
ii),
we
proposed
to
require
an
owner
or
operator
to
address
in
the
Plan
the
type
and
quantity
of
oil
stored
at
the
facility.

Comment:
"Because
the
way
a
tank
is
used
changes
often
and
the
adequacy
of
response
to
an
accidental
discharge
does
not
hinge
on
the
type
of
oil
stored,
Conoco
cannot
support
this
requirement."
(75)

Response:
We
have
eliminated
proposed
§112.7(
a)(
3)(
ii)
in
the
final
rule
because
it
repeats
information
requested
in
revised
§112.7(
a)(
3)(
i)
We
disagree
with
the
assertion
that
the
responder's
knowledge
of
the
type
of
oil
stored
does
not
affect
the
adequacy
of
response.
Responders
use
different
emergency
measures
for
different
types
of
oil.

X­
C­
4
Estimates
of
quantities
of
oil
potentially
discharged
­
proposed
§112.7(
a)(
3)(
iii)

Background:
In
1991,
in
§112.7(
a)(
3)(
iii),
we
proposed
a
requirement
that
an
owner
or
operator
address
estimates
of
the
quantity
of
oils
that
could
be
discharged.

Comments:
See
section
XI­
C–
12
of
this
document
for
the
comments
on
this
paragraph.

Response:
We
have
eliminated
proposed
§112.7(
a)(
3)(
iii)
in
the
final
rule
because
it
repeats
information
sought
in
§112.7(
b)
regarding
"a
prediction
of
the
direction,
rate
of
flow,
and
total
quantity
of
oil
that
could
be
discharged."
We
address
substantive
comments
under
the
discussion
of
that
paragraph.
161
X­
C­
5
Spill
pathways
­
proposed
§112.7(
a)(
3)(
iv)

Background:
In
1991,
in
§112.7(
a)(
3)(
iv),
we
proposed
to
require
an
owner
or
operator
to
address
possible
spill
pathways
in
the
Plan.

Comments:
See
section
XI­
C­
12
of
this
document
for
comments
on
this
issue.

Response:
We
have
eliminated
proposed
§112.7(
a)(
3)(
iv)
in
the
final
rule
because
it
repeats
information
sought
in
final
§112.7(
b),
which
asks
for
"a
prediction
of
the
direction,
rate
of
flow,
and
total
quantity
of
oil
that
could
be
discharged"
as
a
result
of
each
type
of
major
equipment
failure.
We
address
the
substantive
comments
under
the
discussion
of
that
provision.

X­
C­
6
Spill
prevention
measures
­
§112.7(
a)(
3)(
ii)

Background:
In
1991,
in
§112.7(
a)(
3)(
v),
redesignated
in
the
final
rule
as
§112.7(
a)(
3)(
ii),
we
proposed
to
require
the
owner
or
operator
to
address
in
the
Plan
spill
prevention
measures,
including
procedures
for
routine
handling
of
products.

Comment:
We
should
replace
§112.7(
a)(
3)(
v)
with
the
words
secondary
containment.
(121)

Response:
We
adopted
the
term
discharge
prevention
measures
in
the
final
rule
rather
than
secondary
containment,
because
the
term
encompasses
both
secondary
containment
and
other
discharge
prevention
measures.

X­
C­
7
Spill
controls
and
secondary
containment
­
§112.7(
a)(
3)(
iii)

Background:
In
1991,
in
§112.7(
a)(
3)(
vi),
redesignated
in
the
final
rule
as
§112.
7(
a)(
3)(
iii),
we
proposed
to
require
that
the
owner
or
operator
address
in
the
Plan
spill
controls
such
as
secondary
containment
around
tanks
and
other
structures,
equipment,
and
procedures
for
the
control
of
a
discharge.

Comments:
Drainage
controls.
We
should
replace
this
provision
with
the
requirement
that
owners
or
operators
address
"other
drainage
control
features,
and
the
equipment
(pipes,
pumps,
meters,
etc.)
which
they
protect."
(121)

NASA
standards.
The
National
Aeronautics
and
Space
Administration's
(NASA's)
Scientific
and
Technical
Information
(STI)
Program
standards
should
meet
this
spill
control
requirement.
(140)

Underground
piping,
completely
buried
tanks.
We
should
clarify
that
underground
piping
does
not
need
secondary
containment.
(57)

Response:
Drainage
controls.
We
agree
with
the
commenter.
In
the
final
rule,
we
have
revised
the
requirement
to
refer
to
discharge
or
drainage
controls
to
clarify
that
162
drainage
systems
or
diversionary
ponds
could
serve
as
alternative
means
of
secondary
containment.

NASA
standards.
An
owner
or
operator
may
follow
STI
standards
for
spill
control
if
they
meet
part
112
requirements,
but
must
discuss
in
the
Plan
how
those
standards
meet
these
requirements.

Underground
piping,
completely
buried
tanks.
Underground
piping
is
subject
to
the
secondary
containment
requirements
in
§112.7(
c).
Whether
you
install
secondary
containment
around
such
piping
involves
issues
of
practicability
and
the
reasonable
possibility
of
a
discharge
as
described
in
§112.
1(
b).
The
same
rationale
applies
to
completely
buried
storage
tanks.

X­
C­
8
Spill
countermeasures
­
§112.7(
a)(
3)(
iv)

Background:
In
1991,
in
§112.7(
a)(
3)(
vii)
(redesignated
as
§112.7(
a)(
3)(
iv)
in
the
final
rule),
we
proposed
to
require
the
owner
or
operator
to
address
in
the
Plan
spill
countermeasures
for
spill
discovery,
response,
and
clean­
up
(facility's
capability
and
those
that
might
be
required
of
a
contractor).

Comments:
Contingency
planning.
"For
clarity,
EPA
should
consider
trying
to
consolidate
the
contingency
planning
requirements
located
in
these
paragraphs.
For
example,
112.7(
b)
required
a
prediction
of
total
quantity
of
oil
that
could
be
released
and
prediction
of
the
direction
of
flow.
This
same
information
is
already
required
under
112.
7(
a)(
3)(
iii)
and
(iv).
In
112.
7(
a)(
3)(
vii)
spill
countermeasures
for
spill
discovery,
response,
and
cleanup
are
required.
It
appears
that
this
same
type
of
information
is
again
required
under
112.7(
d)(
1)
where
a
contingency
plan
including
a
description
of
response
plans,
personnel
needs,
and
methods
of
mechanical
containment
are
required."
(16)

Editorial
suggestion.
We
should
change
this
provision
to
require
the
owner
or
operator
to
address
"prevention,
control,
or
countermeasure
features,
other
than
secondary
containment
and
drainage
control,
and
the
equipment
which
they
protect"
in
the
Plan.
(121)

Response:
Contingency
planning.
We
disagree
that
these
provisions
are
duplicative.
Each
section
requires
discrete
information.
Section
112.7(
a)(
3)(
iv)
requires
information
concerning
a
facility's
and
a
contractor's
capabilities
for
discharge
discovery,
response,
and
cleanup.
We
also
note
that
§112.7(
b)
requires
information
concerning
the
potential
consequences
of
equipment
failure.
Section
112.7(
d)(
1)
requires
a
contingency
plan
following
the
provisions
of
part
109,
which
includes
coordination
requirements
with
governmental
oil
spill
response
organizations.

Editorial
suggestion.
We
disagree
with
the
suggestion.
We
believe
the
language
we
proposed,
as
revised,
better
captures
the
information
we
are
seeking.
Our
revised
language
refers
to
discovery,
response,
and
cleanup,
which
are
features
that
are
163
absent
from
the
commenter's
suggestion,
and
for
which
a
discussion
in
the
Plan
is
necessary
in
order
to
be
prepared
for
any
discharges.

X­
C­
9
Disposal
of
recovered
materials
­
§112.7(
a)(
3)(
iv)

Background:
In
1991,
in
§112.7(
a)(
3)(
viii)
(redesignated
as
§112.7(
a)(
3)(
v)
in
the
final
rule),
we
proposed
to
require
the
owner
or
operator
to
address
the
disposal
of
recovered
materials
in
the
Plan.

Comments:
Support
for
proposal.
"Conoco
supports
the
requirement
that
the
plan
address
applicable
state
laws,
federal
laws,
and
disposal
options.
However,
it
would
be
neither
feasible
nor
useful
to
discuss
particular
alternatives."
(75)

Opposition
to
proposal.

Certification.
"Detailed
provisions
for
disposal
of
recovered
materials
is
unreasonable
for
manufacturing
facilities
which
may
have
small
quantities
of
many
types
of
oil
and
petroleum
materials.
A
certification
that
disposal
will
be
in
compliance
with
all
federal
and
state
regulations
should
be
sufficient
for
`small
size'
facilities."
(62)

Regulatory
duplication.
"APC
believes
that
the
disposal
of
material
recovered
are
regulated
by
State
law
and/
or
RCRA
and
a
discussion
of
this
subject
in
the
Plan
is
inappropriate."
(58,
66,
125,
164,
170,
L12)

Specific
options.
"The
proposed
regulations
seem
to
require
that
commitments
be
made
for
specific
disposal
options
for
wastes
which
have
not
been
generated.
The
federal
and
state
solid
waste
disposal
options
and
requirements
are
complex
and
changing.
We
suggest
that
disposal
commitments
in
the
SPCC
Plan
be
limited
to
a
statement
which
commits
to
disposal
of
wastes
in
accordance
with
applicable
regulatory
requirements."
(70,
75,
92,
125,
L12)

Unnecessary.
"SPCC
Plans
prepared
under
the
current
regulation
do
not
require
this
information.
Furthermore,
such
practices
may
already
be
included
in
other
Plans
such
as
Best
Management
Practices
Plans
or
RCRA
Contingency
Plans."
(79)
The
issue
of
waste
disposal
does
not
belong
in
a
document
designed
to
address
preventing
oil
contamination
to
navigable
waters.
(164)
We
should
clarify
why
we
have
included
this
new
provision.
The
disposal
of
oil
spill
clean­
up
waste
does
not
impede
spill
containment
or
clean­
up
activities.
(L12)

Authority.
We
do
not
have
the
authority
under
the
CWA
to
request
this
information.
(28,
58)
164
Bioremediation.
"On­
site
bioremediation
would
be
a
much
more
economical
and
practical
means
of
cleaning
up
an
oil
spill
to
achieve
an
equivalent
environmental
benefit."
(101,
113)

Costs.
The
requirement
to
address
disposal
of
recovered
materials
in
the
Plan
may
have
major
cost
implications.
(31,
165,
L15)

Recycling.
"...(
W)
e
also
believe
the
SPCC
regulation
should
encourage
recycling
of
spilled
oil
to
the
extent
possible."
(61)

Response:
Support
for
proposal.
We
appreciate
the
commenter
support.

Applicability,
necessity
for
proposal.
This
provision
applies
to
all
facilities,
including
mobile
facilities,
because
proper
disposal
of
recovered
materials
helps
prevent
a
discharge
as
described
in
§112.1(
b)
by
ensuring
that
the
materials
are
managed
in
an
environmentally
sound
manner.
Proper
disposal
also
assists
response
efforts.
If
a
facility
lacks
adequate
resources
to
dispose
of
recovered
oil
and
oil­
contaminated
material
during
a
response,
it
limits
how
much
and
how
quickly
oil
and
oil­
contaminated
material
is
recovered,
thereby
increasing
the
risk
and
damage
to
the
environment.
A
commitment
to
dispose
of
materials
in
accordance
with
applicable
laws
is
by
itself
insufficient,
because
we
need
evidence
of
actual
methods
employed.

Onshore
or
offshore
mobile
drilling
and
workover
rigs.
We
disagree
that
either
onshore
or
offshore
mobile
drilling
and
workover
rigs
should
be
exempted
from
this
requirement
because
the
information
necessary
to
this
requirement
is
not
always
site
specific,
and
may
be
included
in
a
general
plan
for
a
mobile
facility.

Authority.
Under
section
311(
j)(
1)(
C)
of
the
CWA,
we
have
authority
to
establish
procedures,
methods,
equipment,
and
other
requirements
to
prevent
and
contain
oil
discharges.
Collecting
information
on
disposal
of
recovered
materials
is
a
procedure
or
method
to
help
prevent
or
contain
discharges.

Bioremediation.
We
disagree
that
this
paragraph
would
preclude
bioremediation
efforts,
as
some
commenters
suggested.
Bioremediation
may
be
a
method
of
proper
disposal.

Cost.
Because
it
does
nothing
more
than
require
that
you
explain
the
method
of
disposal
of
recovered
materials,
we
also
disagree
that
this
provision
is
too
costly.
Also,
we
assume
that
good
engineering
practice
will
in
many
cases
include
a
discussion
of
such
disposal
already.
By
describing
those
methods
in
the
Plan,
you
help
ensure
that
the
facility
has
done
the
appropriate
planning
to
be
able
to
dispose
of
recovered
materials,
should
a
discharge
occur.

Editorial
suggestion.
We
disagree
that
we
should
replace
the
proposed
language
with
language
requiring
that
the
owner
or
operator
dispose
of
materials
in
accordance
with
165
proper
State
and
Federal
regulations.
Our
proposed
language
captures
both
State
and
Federal
regulations
and
is
more
succinct.

Recycling.
We
support
the
recycling
of
spilled
oil
to
the
extent
possible,
rather
than
its
disposal.
For
purposes
of
this
rule,
disposal
of
recovered
materials
includes
recycling
of
those
materials.

Regulatory
duplication.
The
paragraph
merely
requires
that
you
discuss
the
methods
employed
to
dispose
of
recovered
materials;
it
does
not
require
that
materials
recovered
be
"disposed"
of
in
any
particular
manner
nor
is
it
an
independent
requirement
to
properly
dispose
of
materials.
Thus,
there
is
no
infringement
on
or
duplication
of
any
other
State
or
Federal
program
or
regulatory
authority.

X­
C­
10
Contact
list
­
§112.7(
a)(
3)(
vi)

Background:
In
1991,
in
§112.7(
a)(
3)(
ix),
redesignated
in
the
final
rule
as
§112.7(
a)(
3)(
vi),
we
proposed
to
require
that
an
owner
or
operator
include
in
the
Plan
a
contact
list
and
phone
numbers
for
the
facility
response
coordinator,
the
National
Response
Center
(NRC),
clean­
up
contractors,
fire
departments,
the
LEPC,
the
SERC,
and
downstream
water
suppliers.

Comments:
Support
for
proposal.
"The
inclusion
of
an
`Emergency
Contact
List'
is
appropriate.
Kerr­
McGee
E&
P/
USO
(United
States
Onshore)
SPCC
Plans
include
such
a
proposed
Emergency
Contact
List."
(27,
90,
114,
L11)

Agreement
for
response.
We
should
change
our
proposal
to
require
that
the
owner
or
operator
identify
the
following:
"Each
cleanup
contractor
that
has
agreed
in
writing...
to
respond
to
a
spill
at
the
facility,
the
period
of
time
that
the
cleanup
contractor's
commitment
is
valid,
an
enumeration
of
the
types
of
spills
to
which
each
cleanup
contractor
is
licensed
to
remediate,
and
the
listing
of
the
license
number(
s)
and
license
expiration
date(
s)
for
each
cleanup
contractor."
Otherwise,
many
owners
or
operators
will
not
check
whether
the
clean­
up
contractor
list
is
current.
(47)

Applicability.

Mobile
facilities.
Because
they
move
from
site­
to­
site,
we
should
exempt
an
owner
or
operator
of
an
onshore
and
offshore
mobile
drilling
and
workover
rigs
from
our
§112.7(
a)(
3)(
vii)­(
ix)
requirements
to
list
spill
countermeasures,
contact
lists,
and
material
disposal
methods
in
the
Plan.
(128)

Authority.
We
do
not
have
the
authority
under
the
CWA
to
require
the
owner
or
operator
to
list
State
emergency
response
phone
numbers
in
this
provision
of
the
Plan.
Such
a
requirement
is
within
the
State's
exclusive
authority.
(58)

Downstream
water
suppliers.
166
Affected
by
a
discharge.
"This
requirement
should
be
modified
to
make
clear
that
only
downstream
water
suppliers
who
might
reasonably
be
affected
by
a
discharge
must
be
notified."
(28,
31,
92,
101,
125,
165,
170,
189,
L02,
L15)

Alternatives
to
notice.
"In
addition,
the
facility
operator
should
be
given
the
option
of
notifying
the
local
entities
such
as
the
local
emergency
planning
committee
and
leave
the
notification
of
individual
water
suppliers
to
that
body."
(62,
66,
92,
125,
170,
189)

Basis
for
estimates.
We
should
base
the
applicability
of
§112.
7(
a)(
3)(
ix)
on
estimates
of
quantities
of
oils
potentially
discharged.
(28)

Case­
by­
case
determination.
An
owner
or
operator
should
assess
each
spill,
and
determine
case­
by­
case
which
downstream
water
suppliers
to
notify.
(66)

Central
registry
of
suppliers.
"Where
does
an
operator
obtain
a
list
of
water
suppliers?
Water
suppliers
should
be
located
in
a
central
registry
to
help
operators
discover
who
they
are."
(28,
31,
165,
L15)

Distance.
"There
must
be
a
downstream
distance
limit
placed
on
this
based
on
estimates
of
quantities
of
oil
potentially
discharged.
This
should
not
include
private
wells."
(28,
31,
92,
101)

"Endless"
list.
A
list
of
downstream
water
suppliers
could
be
endless.
The
LEPC
or
the
U.
S.
Coast
Guard
should
determine
which
downstream
water
suppliers
to
alert.
(164)

Suppliers
of
record.
Only
"water
suppliers
of
record"
should
be
notified.
(31,
165,
L15)

Unnecessary
requirement.
This
requirement
is
unnecessary
and
costly
for
Appalachian
producers.
(101)
Local
and
State
emergency
response
authorities
already
collect
all
information
regarding
downstream
water
suppliers
pursuant
to
the
Federal
Emergency
Planning
and
Community
Right­
to­
Know
Act,
and
regulations
promulgated
thereto.
This
paragraph
should
be
deleted
and
removed
to
a
response
plan
section
because
the
information
called
for
requires
response
information.
(62,
189)

Whom
should
be
notified.

Agencies
notified
of
accidental
discharges.
In
keeping
with
the
SPCC
Program's
focus
on
accidental
discharge
prevention
and
response,
we
should
require
that
the
contact
list
include
only
those
State
and
Federal
agencies
that
must
be
notified
of
an
accidental
oil
discharge.
(75)
167
LEPC,
SERC,
USCG.
We
should
require
owners
or
operators
to
include
only
the
LEPC,
SERC,
and
the
U.
S.
Coast
Guard
in
the
contact
list.
(164)

Response:
Support
for
proposal.
We
appreciate
commenter
support.

Agreement
for
response.
In
response
to
a
comment,
we
have
amended
the
rule
to
require
that
the
cleanup
contractor
listed
must
be
the
one
with
whom
the
facility
has
an
agreement
for
response
that
ensures
the
availability
of
the
necessary
personnel
and
equipment
within
appropriate
response
times.
An
agreement
to
respond
may
include
a
contract
or
some
less
formal
relationship
with
a
cleanup
contractor.
No
formal
written
agreement
to
respond
is
required
by
the
SPCC
rule,
but
if
you
do
have
one,
you
must
discuss
it
in
the
Plan.

Applicability,
mobile
facilities.
We
disagree
that
either
onshore
or
offshore
mobile
drilling
and
workover
rigs
should
be
exempted
from
this
requirement
because
the
information
necessary
to
this
requirement
is
not
always
site
specific,
and
may
be
included
in
a
general
plan
for
a
mobile
facility.

Authority.
We
have
ample
authority
to
ask
for
information
concerning
emergency
contacts
under
the
CWA
because
it
is
relevant
to
the
statute's
prevention,
preparedness,
and
response
purposes.
CWA
section
311(
m)(
2).
Furthermore,
it
is
an
appropriate
question
for
all
facilities,
including
mobile
facilities,
because
it
is
necessary
to
prepare
for
discharges
and
to
aid
in
prompt
cleanup
when
they
occur.
Having
a
Plan
which
contains
a
contact
list
of
response
organizations
is
a
procedure
and
method
to
contain
a
discharge
of
oil
as
specified
in
CWA
section
311(
j)(
1)(
C).

Downstream
water
suppliers.
We
have
deleted
the
reference
to
"downstream
water
suppliers"
(i.
e.,
intakes
for
drinking
and
other
waters)
because
facilities
may
have
no
way
to
identify
such
suppliers.
We
agree
with
commenters
that
identifying
such
suppliers
is
more
a
function
of
State
and
local
emergency
response
agencies.
We
note,
however,
that
facilities
that
must
prepare
response
plans
under
§112.20
must
discuss
in
those
plans
the
vulnerability
of
water
intakes
(drinking,
cooling,
or
other).

Response
section.
We
disagree
that
the
information
should
be
placed
in
a
response
section,
because
most
SPCC
facilities
are
not
required
to
have
response
plans,
and
the
information
is
necessary
to
prepare
for
response
to
an
emergency.

Whom
should
be
notified.
We
have
eliminated
references
to
specific
State
and
local
agencies
in
the
event
of
discharges
in
favor
of
a
reference
to
"all
appropriate
State
and
local
agencies."
"Appropriate"
means
those
State
and
local
agencies
that
must
be
contacted
due
to
Federal
or
State
requirements,
or
pursuant
to
good
engineering
practice.
You
may
not
always
be
required
to
notify
fire
departments,
local
emergency
planning
committees
(LEPCs),
and
State
emergency
response
commissions
(SERCs),
nor
as
an
engineering
practice
do
they
always
need
to
receive
direct
notice
from
the
facility
in
the
event
of
a
discharge
as
described
in
§112.
1(
b).
At
times
they
might,
but
they
might
also
receive
notice
from
other
sources,
such
as
the
National
Response
168
Center.
Other
State
and
local
agencies
might
also
need
notice
from
you.
We
have
added
the
word
"Federal"
to
the
list
of
all
appropriate
contact
agencies
because
there
are
times
when
you
must
notify
EPA
of
certain
discharges.
See
§112.4(
a).
There
might
also
be
requirements
under
other
Federal
statutes,
other
than
the
CWA,
for
notice
in
such
emergencies.

X­
C­
11
Spill
reporting
requirements
­
§112.7(
a)(
4)

Background:
In
1991,
in
§112.7(
a)(
4),
we
proposed
to
require
that
the
owner
or
operator
include
in
the
Plan
documentation
enabling
a
person
reporting
a
spill
to
provide
essential
information.

Comments:
Opposition
to
proposal,
necessity
for
it.
We
should
not
expand
the
Plan
content
requirements
if
we
seek
to
simplify
the
Plan.
Provisions
such
as
the
spill
reporting
requirements
in
(a)(
4)
"frustrate
any
attempts
to
clarify
the
regulatory
framework."
(42)
We
should:
"Delete
and
remove
to
response
plan."
(117,
121)

Documentation.
Rather
than
requiring
an
owner
or
operator
to
provide
documentation
in
the
Plan,
we
should
require
that
"the
information
addressed
in
the
Plan
shall
enable
a
person"
to
report
a
spill
in
accordance
with
the
rest
of
the
paragraph's
requirements.
By
requiring
documentation,
we
would
decrease
the
Plan's
usefulness
as
an
emergency
response
tool.
(75)

Delayed
reporting.
We
should
not
require
documentation
that
may
be
unavailable
to
the
person
initially
reporting
the
spill,
or
highly
speculative.
If
we
require
this
information
from
the
spill
reporter,
notification
from
the
facility
may
be
less
prompt.
(16)

Future
event.
"It
is
not
possible
to
provide
`documentation
in
the
Plan'
which
will
enable
a
person
reporting
a
spill
to
provide
information
on
the
spill
date,
time,
type
of
materials
spilled,
estimation
of
the
total
quantity
spilled,
etc.,
if
the
spill
has
not
happened.
Suggest
that
this
section
be
qualified
to
indicate
that
a
form
for
collecting
such
information
be
included
either
in
the
plan,
or
for
`small
size
facilities'
in
the
HAZWOPER
reporting
matrix."
(62)

Inapplicable
information.
Some
of
the
information
we
would
require
may
not
apply
to
a
wide
variety
of
facilities.
(167,
175)

Unavailable
information.
"Not
all
of
the
information
listed
for
the
purposes
of
reporting
a
release
will
be
`available'
to
the
person
reporting
the
discharge
or
`applicable'
to
the
discharge
incident
or
to
the
facility
at
which
the
release
took
place."
(67,
85,
117,
167,
175)

Editorial
suggestion.
We
should
replace
the
word
spill
with
the
word
discharge
or
release.
A
spill
does
not
necessarily
result
in
a
discharge
or
a
release
to
navigable
169
waters,
and
we
should
not
require
reporting
when
a
spill
or
leak
has
been
fully
contained.
(39)

Facility
address
and
phone
number.
Many
facilities
have
no
address
or
telephone.
We
should
require
that
an
owner
or
operator
provide
the
facility
location
rather
than
the
address
and
phone
number.
(28,
67,
70,
128,
133,
167,
L12)

Response
plan.
"This
is
part
of
response.
Delete
and
remove
to
response
plan."
(121)

State
requirements.
The
spill
reporting
provision
duplicates
State
regulations.
(167)

Response:
Opposition
to
proposal,
necessity
for
it.
We
disagree
that
we
should
eliminate
a
requirement
to
provide
information
and
procedures
concerning
the
cause
of
a
discharge
or
its
effects.
Such
information
and
procedures
in
the
Plan
is
necessary
to
enable
a
person
reporting
a
discharge
to
accurately
describe
information
concerning
that
occurrence
to
the
proper
persons
in
an
emergency.

Documentation.
We
agree
with
commenters
that
the
word
"documentation"
is
inappropriate
because
it
refers
to
a
past
event.
Accordingly,
as
suggested
by
commenters,
we
have
revised
the
rule
to
provide
for
"information
and
procedures"
that
would
assist
the
reporting
of
discharges
as
described
in
§112.1(
b).
"Information"
refers
to
the
facts
which
you
must
report,
and
"procedures"
refers
to
the
method
of
reporting
those
facts.
Such
procedures
must
address
whom
the
person
relating
the
information
should
call,
in
what
order
the
caller
should
call
potential
responders
and
others,
and
any
other
instructions
necessary
to
facilitate
notification
of
a
discharge
as
described
in
§112.1(
b).
If
properly
noted,
the
information
and
procedures
in
the
Plan
should
enable
a
person
reporting
a
discharge
to
accurately
describe
information
concerning
that
occurrence
to
the
proper
persons
in
an
emergency.
Any
information
or
procedure
not
applicable
will
not
have
to
be
used.
Available
information
on
a
discharge
must
be
reported.
Applicable
procedures
must
be
followed.
And
of
course,
any
information
that
is
not
available
cannot
be
reported.

Editorial
suggestion.
In
the
final
rule
we
have
replaced
spill
with
the
term
"discharge
of
oil
as
described
in
§112.1(
b)."
If
a
discharge
is
fully
contained
and
never
reaches
navigable
water
or
adjoining
shorelines,
it
need
not
be
reported.

Facility
address
and
phone
number.
In
the
final
rule
we
have
changed
address
to
address
or
location
because
some
facilities
do
not
have
an
exact
address.
Location
may
mean
the
longitude
and
latitude
of
the
facility
or
some
other
identifiable
means
of
pinpointing
the
facility.
The
phone
number
must
be
accurate,
if
the
facility
has
a
phone.
Of
course,
if
the
facility
has
no
phone,
that
fact
must
be
noted.

State
requirements.
While
it
is
possible
that
this
information
may
be
duplicative
of
State
requirements,
the
duplication
is
eliminated
to
the
extent
that
you
use
your
State
SPCC
Plan
for
Federal
SPCC
purposes.
Where
there
is
no
State
requirement,
there
is
no
duplication.
170
Response
plan
exemption.
We
disagree
that
this
paragraph
should
be
placed
in
a
response
section,
because
most
SPCC
facilities
are
not
required
to
have
response
plans,
and
the
information
is
necessary
to
prepare
for
response
to
an
emergency.
If
your
facility
has
prepared
and
submitted
a
response
plan
to
us
under
§112.20,
there
is
no
need
to
document
this
information
in
your
SPCC
Plan,
because
it
is
already
contained
in
the
response
plan.
See
§112.20(
h)(
1)(
i)­(
viii).
Therefore,
we
have
amended
the
rule
to
exempt
those
facilities
with
response
plans
from
the
requirements
of
this
paragraph.

X­
C­
12
Fault
analysis
­
§112.7(
b)

Background:
Proposed
§112.7(
b)
would
require
an
analysis
of
the
major
types
of
failures
possible
in
a
facility,
including
a
prediction
of
the
direction,
rate
of
flow,
and
total
quantity
of
oil
that
could
be
discharged
as
a
result
of
such
failures.

Comments:
Applicability.

Large
facilities.
"Such
an
effort
with
its
associated
risk
assessment
is
very
complex
and
is
not
needed
for
most
regulated
facilities.
EPA
should
specify
that
such
an
analysis
is
only
required
for
very
large
facilities
with
potential
for
major
harm
to
nearby
receptors.
Small
to
medium­
sized
facilities
should
limit
such
analyses
to
the
identification
of
receptors
located
in
spill
pathways."
(51,
62,
107,
165,
192,
L15,
L17)

Mobile
facilities.
We
should
exempt
mobile
facilities
from
the
requirement
that
owners
or
operators
include
in
the
Plan
site­
specific
information
on
flow
direction,
rate
of
flow,
and
quantity
of
oil
discharged.
Site­
specific
information
changes
when
the
equipment
moves.
(128)

Present
rule
adequate.
"API
believes
that
the
current
section
112.7(
b)
language
is
clearer
and
specifically
focuses
limited
resources
on
situations
for
which
there
is
a
reasonable
potential
for
a
discharge.
Limited
resources
should
not
be
consumed
in
developing
flow
rate,
direction
and
quantity
predictions
in
the
SPCC
Plan
for
situations
without
a
reasonable
potential
for
discharge
to
navigable
waters."
(67,
85)
The
provision
is
useless
and
should
be
deleted.
(28,
101,
164)

Editorial
suggestions.
We
should
replace
possible
spill
pathways
with
most
likely
spill
pathways
to
navigable
waters.
We
should
explain
the
need
for
this
provision
and
allow
public
review
of
this
explanation
before
publishing
the
final
rule.
The
realm
of
potential
pathways
would
be
increased
by
the
inclusion
of
the
EPA­
recommended
25­
year
storm
event.
Our
proposal
would
encourage
an
exploration
and
production
(E&
P)
operator
to
exclude
non­
oil­
storage
portions
of
a
facility
in
the
Plan,
which
would
increase
the
"oil
pollution
potential."
(L12)
171
We
should
replace
"direction...
of
oil...
of
each
major
type
of
failure"
with
the
requirement
that
the
owner
or
operator
include
a
prediction
of
"the
most
likely
spill
to
reach
navigable
waters."
(L12)

Electrical
equipment.
Facilities
with
electrical
equipment
should
be
exempted
from
this
analysis.
(125)

Failure
factors.
The
rule
should
clarify
how
detailed
the
analysis
of
potential
spill
pathways
should
be.
(156)

Flowlines
or
gathering
lines.
Discharge
estimates
for
these
lines
would
be
meaningless
and
requested
that
we
clarify
the
provision.
(28)
For
flowlines
or
gathering
lines,
it
is
impossible
for
the
owner
or
operator
to
estimate
the
quantities
of
oil
potentially
discharged.
(101)

Major
failures.
"First,
EPA
has
not
defined
a
major
type
of
failure
and
would
need
to
give
the
regulated
community
some
guidance
in
this
area.
If
it
were
tuned
to
bulk
storage
tanks,
as
defined
above,
this
could
address
tank
failures
which
have
the
capability
of
releasing
20,
000
or
more
gallons."
(164)

Obvious
scenarios.
"This
provision
is
totally
unnecessary
insofar
as
the
Appalachian
producers
are
concerned.
It
is
overly
involved
for
small
operators
to
imagine
every
conceivable
type
of
failure,
and
calls
for
a
creative
imagination
in
a
place
where
such
is
not
required.
Only
obvious
scenarios,
such
as
tank
rupture
or
leakage
are
necessary
considerations
for
anticipating
cleanup
efforts."
(28,
31,
101,
175)

Small
discharges.
"Section
112.7(
b)
should
be
clarified
to
emphasize
that
the
focus
of
the
SPCC
Plan
should
be
on
assuring
that
any
release
is
prevented
and
mitigated,
not
just
`major'
releases.
Facilities
routinely
experience
and
manage
smaller
releases,
while
major
spills
are
comparatively
rare."
(175)

Spill
history.
We
should
clarify
whether
we
intend
to
require
predicting
the
number
and
degree
of
discharges
based
upon
spill
history.
Predictions
based
on
this
history
would
be
unreliable,
and
we
should
delete
the
provision.
(143)

Response:
Applicability.
We
agree
with
the
commenter
that
current
language
is
clearer
and
will
retain
it.
We
therefore
modified
the
first
sentence
contained
in
the
proposed
rule.
We
agree
that
the
Plan
must
only
discuss
potential
failure
situations
that
might
result
in
a
discharge
from
the
facility,
not
any
failure
situation.
The
rule
requires
that
when
experience
indicates
a
reasonable
potential
for
failure
of
equipment,
the
Plan
must
contain
certain
information
relevant
to
those
failures.
"Experience"
includes
the
experience
of
the
facility
and
the
industry
in
general.

We
disagree
that
the
requirement
is
too
difficult
for
owners
or
operators
of
small
or
mobile
facilities,
or
of
flowlines
or
gathering
lines,
or
of
electrical
equipment
facilities,
or
172
other
users
of
oil.
We
believe
that
a
Professional
Engineer
may
evaluate
the
potential
risk
of
failure
for
the
aforementioned
facilities
and
equipment
and
predict
with
a
certain
degree
of
accuracy
the
result
of
a
failure
from
each.
We
note
that
since
we
have
raised
the
regulatory
threshold,
this
requirement
will
not
be
applicable
to
many
smaller
facilities.

We
also
disagree
that
our
proposal
would
encourage
an
exploration
and
production
(E&
P)
operator
to
exclude
non­
oil­
storage
portions
of
a
facility
in
the
Plan,
which
would
increase
the
"oil
pollution
potential."
A
description
of
the
possible
direction
and
rate
of
flow
of
discharged
oil
includes
any
area
over
which
that
oil
may
flow,
including
non­
oil
portions
of
a
facility.

Editorial
suggestions.
In
final
§112.7(
b),
we
use
the
term
"a
prediction
of
the
direction,
rate
of
flow,
and
total
quantity
of
oil
which
could
be
discharged"
instead
of
the
term
"possible
spill
pathways."

Failure
factors.
To
comply
with
this
section,
you
need
only
address
"major
equipment"
failures.
A
major
equipment
failure
is
one
which
could
cause
a
discharge
as
described
in
§112.
1(
b),
not
a
minor
failure
possibility.
To
help
clarify
the
type
of
equipment
failures
the
rule
contemplates,
we
have
added
examples
of
other
types
of
failures
that
would
trigger
the
requirements
of
this
paragraph.
Such
other
equipment
failures
include
failures
of
loading/
unloading
equipment,
or
of
any
other
equipment
known
to
be
a
source
of
a
discharge.
The
analysis
required
will
depend
on
the
experience
of
the
facility
and
how
sophisticated
the
facility
equipment
is.
If
your
facility
has
simpler
equipment,
you
will
have
less
to
detail.
If
you
have
more
sophisticated
equipment,
you
will
have
to
conduct
a
more
detailed
analysis.
If
your
facility's
experience
or
industry
experience
in
general
indicates
a
higher
risk
of
failure
associated
with
the
use
of
that
equipment,
the
analysis
must
also
be
more
detailed.
This
rationale
and
analytic
detail
are
also
applicable
to
electrical
equipment
facilities
and
other
facilities
that
do
not
store
oil,
but
contain
it
for
operational
use.
Again,
the
required
explanation
will
be
tailored
to
the
type
of
equipment
used
and
the
experience
with
that
equipment.

Spill
pathways.
The
level
of
analysis
concerning
spill
pathways
will
depend
on
the
geographic
characteristics
of
the
facility's
site
and
the
possibility
of
a
discharge
as
described
in
§112.1(
b)
that
equipment
failure
might
cause.
However,
the
Professional
Engineer
should
focus
on
the
most
obvious
spill
pathways.
The
level
of
analysis
required
for
prediction
of
spill
pathways
is
that
which
may
be
reasonably
foreseen,
given
the
physical
location
of
the
facility.
We
have
not
included
a
25­
year
storm
event
standard
in
the
rule,
so
that
calculation
may
not
be
applicable.

Because
this
information
is
facility
specific,
the
owner
or
operator
of
a
mobile
facility
will
not
be
able
to
detail
spill
pathways
in
the
general
Plan
for
the
facility
each
time
the
facility
moves.
However,
the
owner
or
operator
must
provide
management
practices
in
the
general
Plan
that
provide
for
containment
of
discharges
in
spill
pathways
in
a
variety
of
geographic
conditions
likely
to
be
encountered.
In
case
of
a
discharge
at
a
particular
facility,
the
owner
or
operator
would
then
take
appropriate
action
to
contain
173
or
remove
the
discharge.
For
example,
the
Plan
may
provide
that
a
rig
must
be
positioned
to
minimize
or
prevent
discharges
as
described
in
§112.1(
b);
or
it
may
provide
for
the
use
of
spill
pans,
drip
trays,
excavations,
or
trenching
to
augment
discharge
prevention.

X
­
D:
Secondary
containment
­
§112.7(
c)

Background:
Section
112.7(
c)
of
the
current
rule
lists
appropriate
containment
and
diversionary
structures,
or
equipment,
and
among
other
things
requires
that
dikes,
berms
or
retaining
walls
be
"sufficiently
impervious
to
contain
spilled
oil."
In
1991,
we
proposed
to
revise
§112.7(
c)
to
require
that
the
entire
containment
system,
including
the
walls
and
floor,
must
be
impervious
to
oil
for
72
hours.

Comments:
Applicability.

Electric
utilities.
"Specifically,
the
Agency
has
recognized
that
it
is
often
impracticable
to
provide
at
electrical
substations
the
secondary
containment
required
by
proposed
section
112.7(
c)."
(125)

Flowlines,
fired
vessels,
pressured
process
vessels.
"A
statement
should
be
included
in
the
preamble
to
clarify
that
section
112.7(
c)
does
not
require
dikes
around
flowlines,
fired
vessels
or
pressured
process
vessels
at
onshore
producing
facilities.
Industry's
current
practice
is
to
construct
dikes
primarily
around
storage
tanks.
We
think
that
this
constitutes
`good
engineering
practice'."
(125,
133)

Heavy
oils.
The
requirement
should
not
apply
to
tanks
holding
No.
5
and
No.
6
fuel
oils
and
asphalts.
(54)

Mining
sites.
"The
proposed
containment
requirements
will
be
excessive
for
most
mining
operations
and
will
require
redesign
in
many
instances
with
little
resultant
net
environmental
benefit."
(35)

Mobile
facilities.
"Many
of
these
tanks
are
moved
from
location
to
location
on
a
daily
basis.
Many
are
too
small
to
require
a
SPCC
Plan
or
located
at
a
site
with
sufficient
oil
capacity
to
require
a
SPCC
Plan.
Secondary
containment
may
not
be
feasible
in
these
situations."
(190)

Phase­
in.
We
should
adopt
a
phased­
in
approach
so
that
owners
or
operators
would
not
have
to
comply
immediately
with
this
new
provision.
(31,
182)

Production
facilities.
We
should
exempt
production
facilities,
and
allow
a
contingency
plan
instead.
(28,
31,
86,
165)

Underground
piping.
We
should
clarify
that
underground
piping
is
not
subject
to
the
rule's
secondary
containment
provisions.
(71)
174
Contingency
planning
or
containment.

Contingency
plan
alternative.
We
should
revise
the
provision
to
allow
owners
or
operators
to
use
contingency
planning
in
lieu
of
diking
tanks
or
other
equivalent
measures.
(110)

No
equivalent.
We
should
place
greater
emphasis
on
secondary
containment
as
an
oil
storage
method
that
has
no
equivalent.
(121)

Editorial
suggestions.

Primary
containment
system.
We
should
define
primary
containment
system.
(71)

Surface
waters.
We
should
define
the
term
surface
waters.
We
should
change
surface
waters
to
navigable
waters
to
be
consistent
with
the
Clean
Water
Act.
(54,
58,
67,
91,
133,
167,
175)

Floors.
The
impervious
requirement
should
apply
only
to
horizontal
releases
and
not
vertical
releases,
because
vertical
releases
(releases
into
the
ground)
do
not
pose
a
risk
to
navigable
waters.
(48)
We
should
omit
any
reference
to
containment
"floors"
in
the
final
rule,
because
the
purpose
of
the
regulation
is
to
prevent
discharge
to
surface
waters
and
not
to
ground
water.
(1155
(1993
commenter))

Impermeability.

Support
for
72­
hour
standard.
"Not
only
is
this
provision
essential
to
the
protection
of
surface
water,
it
will
provide
some
protection
for
groundwater.
Improperly
constructed
dikes
have
resulted
in
several
groundwater
pollution
problems
of
significant
extent
in
this
state.
The
Department
has
recently
revised
its
rules
to
require
relatively
impervious
dike
structures
at
all
sites
storing
any
substance
likely
to
cause
pollution
of
a
water
of
this
state.
No
exemptions
to
this
requirement
should
be
granted
because
of
facility
size
or
quantity
of
oil
stored."
(4,
143,
185,
L17).

Editorial
suggestion.
We
should
revise
the
standard
as
"impervious
to
oil
and
water
for
72
hours."
(80)

Opposition
to
72­
hour
standard.
(11,
25,
31,
35,
42,
48,
57,
66,
67,
71,
72,
74,
75,
78,
85,
86,
91,
101,
102,
110,
114,
116,
125,
155,
156,
164,
170,
173,
175,
177,
182,
184,
L3,
L30).

Current
standard
is
adequate.
The
current
"sufficiently
impervious"
standard
was
adequate.
(31,
35,
42,
71,
78,
86,
92,
113,
155,
L3)
175
No
environmental
benefit.
If
adopted,
the
72­
hour
impermeability
standard
would
require
owners
or
operators
to
modify
existing
secondary
containment
structures.
Owners
or
operators
would
spend
a
significant
amount
of
money
on
these
modifications
for
no
additional
environmental
benefit.
(11,
25,
28,
34,
35,
48,
58,
75,
90,
95,
101,
102,
110,
113,
139,
165,
167,
173,
175,
182,
1155
(1993
comment))

Alternate
standards.

§112.8(
c)
standard.
We
should
use
the
language
proposed
in
§112.8(
c)(
2)
in
§112.7(
c).
The
§112.8(
c)(
2)
approach
would
permit
some
contamination
of
the
containment
system,
without
sanctioning
an
oil
discharge
to
surface
waters.
(34,
77)

Containment
instead.
The
rule
should
address
containment
rather
than
impermeability;
the
reason
for
a
containment
structure
is
to
keep
a
discharge
from
reaching
navigable
waters.
(25,
34,
74,
116,
164,
170,
L30)

Containment
or
cleanup.
We
should
give
facilities
a
choice
between
renovating
containment
to
be
impervious
for
72
hours
and
providing
for
the
expedient
clean­
up
of
a
spill.
(90)

Liners.
"In
lieu
of
a
requirement
for
total
imperviousness,
specify
acceptable
liner
materials
such
as
compacted
clay,
plastic,
asphalt
or
concrete,
and
corresponding
levels
of
acceptable
permeability."
(107)

Monitoring.
"While
supporting
this
clarification,
it
should
also
be
recommended
that
if
a
truly
impervious
containment
is
not
provided,
a
check
should
be
made
of
available
geological
records
and
documents,
site
conditions,
etc.,
to
assure
that
such
conduits
that
may
cause
substantial
migration
of
free
product
are
appropriately
monitored
for
discharges."
(76)

Alternate
time
frames.

24
hours,
manned
facilities.
Suggests
language
requiring
the
containment
system
to
"be
constructed
to
contain
released
oil
for
at
least
24
hours"
if
it
is
"normally
attended
during
typical
work
hours."
"A
requirement
this
strenuous
is
unnecessary
in
situations
where
personnel
are
present
during
a
routine
workweek."
(183)

More
than
24
hours,
unmanned
facilities.
"As
an
alternative,
this
requirement
should
be
revised
such
that
it
is
applicable
only
to
facilities
that
go
unmanned
for
more
than
24
hours
at
any
one
time."
(102)
176
36
hours
and
inspections.
In
addition
to
the
72
hour
standard,
EPA
should
allow
"alternate
requirements
which
would
allow
for
expedient
cleanup
of
spills,
e.
g.,
within
36
hours,
and/
or
an
increased
frequency
of
inspections."
(90)

72
hours;
"As
soon
as
practicable."
"If
the
potential
exists
for
the
oil
to
reach
surface
waters,
then
immediate
cleanup
within
72
hours
would
be
appropriate.
For
all
other
types
of
oil
spills,
it
could
be
required
that
clean
up
measures
should
be
initiated
as
soon
as
practicable
with
proper
containment
measures
in
place
within
72
hours."
(22,
125,
L20)

"Duration
of
the
emergency
response."
Containment
structures
should
be
"sufficiently
impervious
to
retain
oil
for
the
duration
of
the
emergency
response."
(75,
87)

No
time
limit.
"The
inclusion
of
a
specific
time
frame
is
not
necessary.
While
API
would
agree
that
72
hour
retention
may
be
a
realistic
goal
in
most
cases,
we
discourage
the
use
of
any
specified
amount
of
time
applied
universally
and
instead
recommend
that
the
SPCC
regulations
establish
the
intent
and
allow
the
regulated
community
the
opportunity
to
meet
that
intent."
(25,
66,
67,
78,
85,
91,
95,
102,
133,
175)

Applicability.

Attended
facilities.
The
72­
hour
standard
is
unnecessary
for
facilities
that
are
attended
24
hours
a
day,
because
facility
employees
will
find
a
spill
within
a
few
hours.
(39,
48,
62,
87,
95,
102,
124,
125,
155,
173,
175,
182,
L8,
L30)
This
requirement
should
apply
only
to
those
facilities
that
are
unattended.
(183,
L18)
We
should
require
the
72­
hour
standard
only
at
a
facility
that
is
unmanned
for
more
than
42
consecutive
hours.
(182)

Environmentally
sensitive
areas.
Only
owners
or
operators
of
facilities
in
environmentally
sensitive
areas
(e.
g.,
wetlands)
should
have
to
meet
the
72­
hour
standard.
(114)

New
facilities
only.
The
72­
hour
impermeability
requirement
should
apply
to
new
facilities
only.
(165,
182,
192)

Calculation
of
72
hours.
Asks
when
72
hours
begins
to
run,
from
discovery
of
the
discharge
or
time
of
occurrence.
(82)

Clarification
of
"impervious"
needed.
We
should
further
define
"impervious
to
oil
for
72
hours"
in
the
proposed
standard.
(9,
34,
58,
67,
68,
70,
71,
76,
81,
83,
87,
91,
92,
95,
98,
101,
107,
114,
115,
117,
125,
133,
179,
182,
187,
L2,
L12)
We
should
define
impervious
in
terms
of
engineering
standards.
(27,
57,
87,
101,
114,
135,
175,
177,
186,
190)
177
Good
engineering
practice.
We
should
revise
the
standard
to
make
clear
that
the
impervious
determination
should
be
based
on
good
engineering
practice.
(125)

Showing
impermeability.
Asks
how
to
prove
that
facility
secondary
containment
systems
are
impervious.
(10,
28,
58,
66,
101,
113,
125,
155,
156,
165,
179,
190)
It
would
be
too
costly
to
prove
that
secondary
containment
systems
were
impervious.
(28,
90,
101,
113,
165,
182)

Methods
of
secondary
containment.

Alternative
structures.
Alternative
secondary
containment
structures
are
impracticable
at
small
facilities.
(182)

Earthen
structures.
"An
arbitrary
requirement
that
a
dike
be
`impervious'
could
be
interpreted
to
require
replacement
of
almost
all
of
the
existing
containment
systems
for
production
locations,
most
of
which
have
earthen
dikes.
Such
containment
systems
prevent
oil
from
migrating
offsite
to
waters
but
may
not
be
completely
`impervious.
'
Given
the
low
level
of
risk
presented
by
such
facilities,
with
their
typically
low
volumes
of
storage,
IPAA
does
not
believe
that
the
proposed
requirements
are
justified."
(28,
31,
34,
39,
67,
74,
75,
77,
86,
91,
101,
107,
110,
113,
133,
164,
165,
167,
186,
187,
195,
L30)

Factory
fabricated.
We
should
clarify
whether
forms
of
construction
with
factory
fabricated
secondary
containment
are
equivalent
forms
of
construction.
(140)

Flexibility.
We
should
maintain
flexibility
in
allowing
owners
or
operators
to
use
one
or
more
secondary
containment
systems.
(39,
54,
70,
71)
We
should
provide
owners
or
operators
flexibility
to
meet
the
protection
standard
in
a
way
that
is
cost
effective
to
them.
(184)

Sorbents
or
booms.
We
should
remove
sorbent
materials
or
booms
from
the
list
of
acceptable
secondary
containment
structures
because
they
are
not
a
substitute
for
impervious
dikes
and
impoundment
floors.
(111)

Sump
pump
or
catchment
basin.
Sump
pumps,
catchment
basins,
or
other
methods
listed
in
§112.9(
b)(
2)
might
be
sufficient.
(28,
31,
167)

Response:
Applicability
of
requirement.
Secondary
containment
is
best
for
most
facilities
storing
or
using
oil
because
it
is
the
most
effective
method
to
stop
oil
from
migrating
beyond
that
containment.
We
believe
that
secondary
containment
is
preferable
to
a
contingency
plan
at
manned
and
unmanned
facilities
because
it
prevents
discharges
as
described
in
§112.1(
b).
At
unmanned
facilities,
it
may
be
even
more
important
because
of
the
lag
in
time
before
a
discharge
may
be
discovered.
Notwithstanding
what
may
be
difficult
terrain,
we
believe
that
some
form
of
secondary
containment
is
practicable
at
most
facilities,
including
remote
production
facilities.
In
178
fact,
it
may
often
be
more
feasible
in
remote
or
rural
areas
because
there
are
fewer
space
limitations
in
such
areas.
For
example,
at
some
remote
mobile
or
production
facilities,
owners
or
operators
dig
trenches
and
line
them
for
containment
or
retention
of
drilling
fluids.
Technologies
used
at
offshore
facilities
to
catch
or
contain
oil
may
also
sometimes
be
used
onshore.

While
some
types
of
secondary
containment
(for
example,
dikes
or
berms)
may
not
be
appropriate
at
certain
facilities,
other
types
(for
example,
diversionary
systems
or
remote
impounding)
might.
However,
we
recognize
and
repeat,
as
we
noted
in
the
1991
preamble,
that
some
or
perhaps
all
types
of
secondary
containment
for
certain
facilities
with
equipment
that
contain
oil,
such
as
electrical
equipment,
may
be
contrary
to
safety
factors
or
other
good
engineering
practice
considerations.
There
might
be
other
equipment,
like
fired
or
pressurized
vessels,
for
which
safety
considerations
also
preclude
some
or
all
types
of
secondary
containment.

Some
facilities
or
equipment
that
use
but
do
not
store
oil
may
or
may
not,
as
a
matter
of
good
engineering
practice,
employ
secondary
containment.
Such
facilities
might
include
wastewater
treatment
facilities,
whose
purpose
is
not
to
store
oil,
but
to
treat
water.
Other
facilities
that
may
not
find
the
requirement
practicable
are
those
that
use
oil
in
equipment
such
as
hydraulic
equipment.
Similarly,
flowlines
must
have
a
program
of
maintenance
to
prevent
discharges.
See
§112.9(
d)(
3).
The
maintenance
program
may
or
may
not
include
secondary
containment.
Owners
or
operators
of
underground
piping
must
have
some
form
of
corrosion
protection,
but
do
not
necessarily
have
to
use
secondary
containment
for
that
purpose.

As
stated
above,
for
a
facility
where
secondary
containment
is
not
practicable,
the
owner
or
operator
is
not
exempt
from
the
requirement,
but
may
instead
provide
a
contingency
plan
and
take
other
measures
required
under
§112.7(
d).
For
most
facilities,
however,
including
small
facilities,
mobile
facilities,
production
facilities,
mining
sites,
and
any
other
facilities
that
store
or
use
oil,
we
believe
that
secondary
containment
is
generally
necessary
and
appropriate
to
prevent
a
discharge
as
described
in
§112.1(
b).
Without
secondary
containment,
discharges
from
containers
would
often
reach
navigable
waters
or
adjoining
shorelines,
or
affect
natural
resources.

Completely
buried
tanks.
Completely
buried
tanks
which
are
not
exempted
from
this
rule
because
they
are
subject
to
all
Federal
or
State
UST
requirements
are
subject
to
the
secondary
containment
requirement.
We
realize
that
the
concept
of
freeboard
for
precipitation
is
inapplicable
to
secondary
containment
for
completely
buried
tanks.
The
requirement
for
secondary
containment
may
be
satisfied
in
any
of
the
ways
listed
in
the
rule
or
their
equivalent.

Contingency
planning
or
containment.
A
contingency
plan
should
not
be
used
routinely
as
a
substitute
for
secondary
containment
because
we
believe
it
is
normally
environmentally
better
to
contain
oil
than
to
clean
it
up
after
it
has
been
discharged.
Secondary
containment
is
intended
to
contain
discharged
oil
so
that
it
does
not
leave
the
facility
and
contaminate
the
environment.
The
proper
method
of
secondary
179
containment
is
a
matter
of
good
engineering
practice,
and
so
we
do
not
prescribe
here
any
particular
method.
Under
part
112,
where
secondary
containment
is
not
practicable,
you
may
deviate
from
the
requirement,
provide
a
contingency
plan
following
the
provisions
of
40
CFR
part
109,
and
comply
with
the
other
requirements
of
§112.7(
d).
For
bulk
storage
containers,
those
requirements
include
both
periodic
integrity
testing
of
the
containers
and
periodic
integrity
and
leak
testing
of
the
valves
and
piping.
You
must
also
provide
a
written
commitment
of
manpower,
equipment,
and
materials
to
expeditiously
control
and
remove
any
quantity
of
oil
discharged
that
may
be
harmful.

Double­
walled
or
vaulted
tanks.
The
term
"vaulted
tank"
has
been
used
to
describe
both
double­
walled
tanks
(especially
those
with
a
concrete
outer
shell)
and
tanks
inside
underground
vaults,
rooms,
or
crawl
spaces.
While
double­
walled
or
vaulted
tanks
are
subject
to
secondary
containment
requirements,
shop­
fabricated
double­
walled
aboveground
storage
tanks
equipped
with
adequate
technical
spill
and
leak
prevention
options
might
provide
sufficient
equivalent
secondary
containment
as
that
required
under
§112.7(
c).
Such
options
include
overfill
alarms,
flow
shutoff
or
restrictor
devices,
and
constant
monitoring
of
product
transfers.
In
the
case
of
vaulted
tanks,
the
Professional
Engineer
must
determine
whether
the
vault
meets
the
requirements
for
secondary
containment
in
§112.7(
c).
This
determination
should
include
an
evaluation
of
drainage
systems
and
of
sumps
or
pumps
which
could
cause
a
discharge
of
oil
outside
the
vault.
Industry
standards
for
vaulted
tanks
often
require
the
vaults
to
be
liquid
tight,
which
if
sized
correctly,
may
meet
the
secondary
containment
requirement.

There
might
also
be
other
examples
of
such
alternative
systems.

Editorial
suggestions.

Primary
containment
system.
In
response
to
the
commenter's
question,
we
note
that
a
primary
containment
system
is
the
container
or
equipment
which
holds
oil
or
in
which
oil
is
used.

Surface
waters.
We
do
not
use
the
term
"surface
waters"
in
the
final
rule.
We
revised
the
proposed
phrase,
"escape
to
surface
waters"
to
read
"escape
from
the
containment
system"
to
reflect
more
clearly
the
intent
of
the
rule
that
secondary
containment
should
keep
oil
from
escaping
from
the
facility
and
reaching
navigable
waters
or
adjoining
shorelines.

72­
hour
impermeability
standard.
We
are
withdrawing
the
proposal
for
the
72­
hour
impermeability
standard
and
will
retain
the
current
standard
that
dikes,
berms,
or
retaining
walls
must
be
sufficiently
impervious
to
contain
oil.
We
agree
with
commenters
that
the
purpose
of
secondary
containment
is
to
contain
oil
from
escaping
the
facility
and
reaching
the
environment.
The
rationale
for
the
72­
hour
standard
was
to
allow
time
for
the
discovery
and
removal
of
an
oil
spill.
An
owner
or
operator
of
a
facility
should
have
flexibility
in
how
he
prevents
a
discharge
as
described
in
§112.
1(
b),
180
and
any
method
of
containment
that
achieves
that
end
is
sufficient.
Should
such
containment
fail,
the
owner
or
operator
must
immediately
clean
up
any
discharged
oil.

Similarly,
because
the
purpose
of
the
"sufficiently
impervious"
standard
is
to
prevent
discharges
as
described
in
§112.1(
b),
dikes,
berms,
or
retaining
walls
must
be
capable
of
containing
oil
and
preventing
such
discharges.
Discharges
as
described
in
§112.1(
b)
may
result
from
direct
discharges
from
containers,
or
from
discharges
from
containers
to
groundwater
that
travel
through
the
groundwater
to
navigable
waters
or
adjoining
shorelines.
Effective
containment
means
that
the
dike,
berm,
or
retaining
wall
must
be
capable
of
containing
oil
and
sufficiently
impervious
to
prevent
discharges
from
the
containment
system
until
it
is
cleaned
up.
The
same
holds
true
for
container
floors
or
bottoms;
they
must
be
able
to
contain
oil
to
prevent
a
discharge
as
described
in
§112.1(
b).
However,
"effective
containment"
does
not
mean
that
liners
are
required
for
secondary
containment
areas.
Liner
are
an
option
for
meeting
the
secondary
containment
requirements,
but
are
not
required
by
the
rule.

If
you
are
the
owner
or
operator
of
a
facility
subject
to
this
part,
you
must
prepare
a
carefully
thought­
out
Plan
in
accordance
with
good
engineering
practice.
A
complete
description
of
how
secondary
containment
is
designed,
implemented,
and
maintained
to
meet
the
standard
of
sufficiently
impervious
is
necessary.
In
order
to
document
that
secondary
containment
is
sufficiently
impervious
and
sufficiently
strong
to
contain
oil
until
it
is
cleaned
up,
the
Plan
must
describe
how
the
secondary
containment
is
designed
to
meet
that
standard.
A
written
description
of
the
sufficiently
impervious
standard
is
not
only
necessary
for
design
and
implementation,
but
will
aid
owners
or
operators
of
facilities
in
determining
which
practices
will
be
necessary
to
maintain
the
standard
of
sufficiently
impervious.
Control
and/
or
removal
of
vegetation
may
be
necessary
to
maintain
the
impervious
integrity
of
the
secondary
containment.
Repairs
of
excavations
or
other
penetrations
through
secondary
containment
will
need
to
be
conducted
in
accordance
with
good
engineering
practices
in
order
to
maintain
the
standard
of
sufficiently
impervious.
The
owner
or
operator
should
monitor
such
imperviousness
for
effectiveness,
in
order
to
be
sure
that
the
method
chosen
remains
impervious
to
contain
oil.

We
note
that
we
have
withdrawn
the
proposed
72­
hour
standard,
and
afford
various
secondary
containment
options,
including
earthen
dikes
and
diked
areas,
if
they
contain
and
prevent
discharges
as
described
in
§112.1(
b).
Therefore,
there
are
no
new
costs.
We
disagree
with
the
commenters
who
asserted
that
we
underestimated
the
cost
to
comply
with
the
secondary
containment
and
truck
loading
area
requirements.
The
revised
rule,
like
the
current
rule,
does
not
require
a
specific
impermeability
for
dikes
and
does
not
require
a
specific
method
of
secondary
containment
at
loading
areas,
and
this
flexibility
is
reflected
in
our
cost
estimates.
We
noted
in
our
1991
Supplemental
Cost/
Benefit
Analysis
that
secondary
containment
for
bulk
storage
tanks
is
estimated
to
cost
$1,
000
for
small
facilities;
$6,
400
for
medium
facilities;
and
$63,000
for
large
facilities.
Unit
cost
estimates
were
developed
for
a
broad
mix
of
facilities
(e.
g.,
farms,
bulk
petroleum
terminals)
in
each
size
category
by
experienced
engineers
with
firsthand
knowledge
of
the
Oil
Pollution
Prevention
181
Regulation
and
the
operations
of
onshore
SPCC­
regulated
facilities.
Because
our
cost
estimates
must
be
representative
of
the
many
types
of
facilities
that
are
regulated,
they
will
underestimate
the
costs
for
some
facility
types
and
overestimate
the
costs
for
others.
Facilities
were
assumed
to
construct
secondary
containment
systems
of
impervious
soil
capable
of
holding
110
percent
of
the
largest
tank.
In
that
analysis,
we
estimated
that
78
percent
and
88
percent
of
the
regulated
community
were
already
in
compliance
with
these
requirements,
respectively,
and
would
not
be
affected
by
the
proposed
rule
change.

Since
we
last
performed
these
analyses,
API
has
issued
several
industry
standards,
including
API
653
and
2610,
which
address
many
of
the
provisions
in
the
SPCC
rule.
As
a
result,
the
final
rule
relies
on
current
industry
standards
and
practices,
where
feasible.
In
the
final
rule,
we
withdrew
the
proposed
72­
hour
impermeability
standard
for
secondary
containment
and
maintained
the
current
requirement
that
dikes,
berms,
and
oil
retaining
walls
must
be
sufficiently
impervious
to
contain
oil.
As
a
result,
the
final
rule
reflects
current
industry
standards
and
we
assume
poses
no
additional
requirements
on
industry.

Industry
standards.
Industry
standards
that
may
assist
an
owner
or
operator
with
secondary
containment
include:
(1)
NFPA
30;
(2)
BOCA,
National
Fire
Prevention
Code;
and,
(3)
API
Standard
2610,
"Design,
Construction,
Operation,
Maintenance,
and
Inspection
of
Terminal
and
Tank
Facilities."

Methods
of
secondary
containment.
We
disagree
that
we
should
remove
sorbent
materials
and
booms
from
the
list
of
acceptable
secondary
containment
structures.
The
appropriate
method
of
secondary
containment
is
an
engineering
question,
and
therefore
we
do
not
prescribe
any
particular
method.
Double­
walled
piping
may
be
an
option,
but
is
note
required
by
these
rules.
Earthen
or
natural
structures
may
be
acceptable
if
they
contain
and
prevent
discharges
as
described
in
§112.1(
b),
including
containment
that
prevents
discharge
of
oil
through
groundwater
that
might
cause
a
discharge
as
described
in
§112.
1(
b).
What
is
practical
for
one
facility,
however,
might
not
work
for
another.
If
secondary
containment
is
not
practicable,
then
the
facility
must
provide
a
contingency
plan
following
the
provisions
of
40
CFR
part
109,
and
otherwise
comply
with
§112.7(
d).

Sufficient
freeboard.
See
the
Response
to
Comments
in
§112.8(
c)(
2)
for
a
discussion
of
this
topic.

X­
E
Contingency
planning
X­
E­
1
­
1991
and
1993
proposals
Background:
1991
proposal.
Current
§112.7(
d)
requires
that,
when
an
owner
or
operator
determines
that
secondary
containment
is
impracticable,
he
must
demonstrate
this
impracticability
and
prepare
a
strong
oil
spill
contingency
plan
following
the
provisions
of
40
CFR
part
109.
In
1991,
we
proposed
several
new
requirements
in
182
§112.7(
d).
We
proposed
language
clarifying
that
the
owner
or
operator
must
submit
the
contingency
plan
to
the
Regional
Administrator
(RA)
for
approval.
Further,
we
replaced
the
reference
to
40
CFR
part
109
with
a
list
of
basic
requirements
for
an
oil
spill
contingency
plan.
We
proposed
language
requiring
that
the
owner
or
operator
make
the
contingency
plan
a
stand­
alone
section
of
the
Plan;
and,
that
he
not
rely
upon
response
methods
other
than
containment
and
physical
removal
of
oil
from
the
water
(e.
g.,
not
rely
on
dispersants
or
other
chemicals),
unless
the
RA
approved
such
response
methods.
We
also
asked
for
general
comments
on
Phase
Two
contingency
planning,
and
specific
comments
and
supporting
data
on
contingency
planning
needs.

Under
§112.7(
d)(
2)
of
the
current
rule,
the
owner
or
operator
of
a
facility
without
secondary
containment
must
provide
a
written
commitment
of
manpower,
equipment,
and
materials
required
to
expeditiously
control
and
remove
any
harmful
quantity
of
discharged
oil
as
part
of
his
contingency
plan.
In
1991,
we
proposed
in
§112.7(
d)(
2)
a
recommendation
that
the
facility
owner
or
operator
consider
factors
such
as
financial
capability
in
making
the
written
commitment
of
manpower,
equipment,
and
materials.

1993
proposal.
In
1993,
we
modified
the
1991
proposal
for
a
facility
that
lacks
secondary
containment
to
require
a
facility
response
plan
as
described
in
§112.20,
instead
of
the
specific
requirements
proposed
in
1991.
The
response
plan
would
not
be
submitted
to
the
Regional
Administrator
for
his
review,
unless
otherwise
required,
but
would
be
maintained
at
the
facility
with
the
SPCC
Plan.

Comments:
Support
for
proposal.
Support
for
proposal
for
elementary
contingency
planning
requirements.
(
61,
91,
175)
Support
for
contingency
planning
as
an
alternative
when
secondary
containment
is
impracticable.
(90,
125)
We
should
separate
prevention
and
response
plan
rules.
(121)

Expanded
requirements.
"3M
believes
that
requirements
for
even
elementary
contingency
plans
should
be
expanded
during
this
rulemaking
to
include
additional
factors.
...
Accordingly,
3M
believes
the
SPCC
regulation
should
expressly
require
the
calculation
of
a
worst
case
scenario
as
part
of
each
contingency
plan.
...
3M
believes
the
SPCC
regulation
should
require
each
contingency
plan
to
document
the
availability
of
enough
sorbent
material
and
other
equipment
to
manage
a
worst
case
spill.
...
The
regulation
should
state
that
the
plan
must
provide
for:
employee
training
in
implementation
of
the
plan,
including
practice
drills;
availability
of
protective
gear
for
all
employees
who
may
be
called
upon
to
respond
to
a
spill;
and,
timely
restocking
of
sorbents
and
protective
gear
after
use.
3M
also
supports
EPA's
plan
to
develop
more
detailed
requirements
for
contingency
plans,
including
vulnerability
analyses
and
event
and
fault
tree
analyses,
as
part
of
the
Phase
Two
rulemaking."
(61,
107)

Response
planning
and
1993
contingency
planning
proposal
­
Phase
II.

Leak
detection.
At
no
time
should
we
require
installing
leak
detection
systems
or
conducting
vulnerability,
and
event
and
fault
tree
analyses
at
a
facility
with
183
adequate
secondary
containment.
(51,
57,
67,
155,
191)
In
the
Phase
Two
regulations,
we
should
require
owners
or
operators
to
install
these
systems
for
all
SPCC
facilities,
because
secondary
containment
could
not
be
effective
for
an
underground
spill
and
early
detection
should
be
a
priority.
(L1)

Performance
standards.
We
should
avoid
making
the
Phase
Two
planning
standards
like
performance
standards.
We
should
not
initiate
an
enforcement
action
against
an
owner
or
operator
who
failed
to
follow
"a
script
or
scenario
laid
down
during
the
planning
process."
(133)

Requirements
premature.
"API
opposes
as
premature,
facility­
specific
contingency
plan
information
needs
(i.
e.,
discovery
of
a
spill,
emergency
notification
procedures,
name
of
the
spill
response
coordinator,
procedures
for
identifying
personnel
and
equipment
that
may
be
needed,
available
equipment
lists,
available
personnel
lists,
an
identification
of
hazards,
a
vulnerability
analysis,
and
an
event
and
fault
tree
analysis.)
Until
EPA
fully
defines,
in
the
Phase
Two
rulemaking,
the
scope
and
limitation
of
these
terms,
justifies
the
informational
needs
in
terms
of
protection
of
human
health
and
the
environment,
and
demonstrates
that
it
is
statutorily
authorized
to
collect
such
information,
it
is
premature
to
require
it
at
this
time.
Area
Committees,
as
mandated
by
the
OPA,
will
be
developing
this
information
directly."
(67)
"The
Agency's
position
appears
to
be
that
specific
contingency
planning
requirements
will
be
developed
in
its
Phase
II
rulemaking.
However,
this
is
of
little
help
to
facilities
that
must
develop
contingency
plans
to
meet
Phase
I
requirements.
Therefore,
we
recommend
that
the
Agency
defer
the
requirement
to
prepare
contingency
plans
until
promulgation
of
the
Phase
II
rules."
(125)
We
should
require
contingency
planning
only
as
part
of
Phase
Two
for
facilities
with
the
potential
to
cause
substantial
harm.
(L12)

Secondary
containment,
not
a
contingency
plan.
"New
York
State
does
not
accept
contingency
plans
in­
place
of
a
secondary
containment
system.
We
recommend
that
all
facilities
threatening
ground
or
surface
waters
have
secondary
containment
facilities."
(111)

Vulnerability
analysis.
The
discussion
of
vulnerability,
event
and
fault
tree
analyses
is
confusing
in
connection
with
the
actual
proposal
in
the
Phase
One
rulemaking.
(34)
"Such
analyses
should
not
be
required
for
facilities
with
secondary
containment.
Furthermore,
if
EPA
should
require
these
analyses,
the
analyses
should
encompass
readily
available
information
and
EPA
should
use
only
clearly
understood
criteria
in
asking
for
information."
(57,
89,
101,
107,
114,
L15).

Downstream
water
suppliers.
"It
is
proposed
that,
under
Phase
II,
a
site­
specific
contingency
plan
will
include
a
vulnerability
analysis,
one
element
of
which
would
be
notification
of
drinking
water
suppliers
[downstream].
Pennsylvania
currently
has
such
a
requirement
that
could
be
considered
to
have
a
flaw.
The
184
Pennsylvania
requirement
is
that
oil
storage
facilities
must
identify
water
users
for
20
miles
downstream,
and
update
that
list
every
year.
Because
the
primary
source
of
such
information
is
at
offices
of
each
county,
the
demands
on
the
facilities
and
county
offices
is
excessive.
In
addition,
facilities
may
not
identify
a
new
water
user
for
nearly
a
year."
(76)

Response:
Support
for
proposal.
We
appreciate
support
for
the
proposal,
but
modified
that
proposal
in
1993.
See
the
preamble
to
today's
final
rule
and
section
4
of
the
1993
Comment
Response
Document
for
a
discussion
on
contingency
planning.
See
below
for
comments
related
to
the
extant
1991
proposal.

Response
planning
and
1993
contingency
planning
proposal
­
Phase
II.
For
an
indepth
discussion
of
issues
in
the
Phase
Two
rulemaking,
see
the
FRP
preamble
and
final
rule
(59
FR
34070,
July
1,
1994),
the
Phase
Two
docket
(SPCC­
2P),
and
the
preamble
to
today's
final
rule.
See
the
preamble
to
today's
final
rule,
section
4
of
the
1993
Comment
Response
Document
for
a
discussion
on
contingency
planning,
and
sections
X­
E,
F,
and
G
of
this
document.

X­
E­
2
General
­
§112.7(
d)

Background.
In
1991,
we
proposed
to
add
language
to
§112.7(
d)(
1)
listing
the
basic
requirements
for
an
oil
contingency
plan,
including
the
phrase
"and
such
other
information
as
required
by
the
RA."

Comments:
Additional
information.
This
language
is
too
broad
and
would
subject
facilities
to
unknown
regulation.
We
should
clearly
specify
what
additional
information
would
be
required
by
t3he
RA
or
change
the
language
to
state
"such
other
information
as
the
RA
may
reasonably
require."
(103)
The
contents
should
include
at
least
the
same
requirements
as
those
found
in
the
Oil
Pollution
Act
(OPA)
amendments
to
the
Federal
Water
Pollution
Control
Act
(FWPCA).
(171)

Applicability.

Aboveground
tanks.
Proposed
§112.7(
d)
should
be
applicable
to
fixed
aboveground
tanks
only.
(102)

Buried
piping,
buried
tanks,
portable
tanks.
Questions
whether
it
was
our
intent
to
require
facilities
"with
buried
piping,
buried
tanks,
or
portable
tanks
for
which
secondary
containment
cannot
be
provided"
to
prepare
and
submit
an
SPCC
Plan.
(102)

Electrical
equipment.
"The
electric
utility
strongly
supports
the
inclusion
in
the
SPCC
rules
of
an
alternative
to
secondary
containment/
drainage
control
requirements
where
such
controls
are
demonstrated
to
be
impracticable.
This
provision
adds
needed
flexibility
to
the
rule
and
again
allows
the
owner
or
operator
to
use
good
engineering
practices
in
adapting
the
goals
of
the
SPCC
185
program
to
unusual
facilities.
As
the
Agency
has
recognized,
secondary
containment
is
impracticable
at
many
electric
utility
substations."
(125)

FRP
facilities.
Re
§112.7(
d):
"When
response
plans
are
to
be
required
of
all
facilities,
this
paragraph
should
be
deleted."
(121)

Large
facilities.
"Suggest
that
contingency
plan
for
"large
facilities"
only
be
provided
to
Regional
Administrator."
(62)

Production
facilities.
"Facility
specific
contingency
plans
are
not
practicable
in
many
cases,
particularly
as
they
relate
to
onshore
oil
production
operations.
The
profitability
of
these
operations,
especially
stripper
operations,
would
be
utterly
destroyed
by
the
costs
associated
with
preparation,
implementation,
review,
revision,
and
other
work
associated
with
contingency
planning."
(42,
58)

Production
flowlines
and
trunklines.
"Language
should
be
included
that
excludes
production
flowlines
and
trunklines
from
this
requirement.
At
most
production
facilities,
dikes
are
installed
around
tank
batteries,
but
not
around
flowlines
because
it
is
impractical
to
do
so.
As
written,
the
regulation
would
require
submission
of
spill
contingency
plans
for
all
such
facilities."
(167)

Rack
to
tank
piping.
"Proposed
section
112.7(
d)
does
not
specifically
address
pipes
running
from
the
terminal
rack
to
a
tank(
s),
that
will
be
by
necessity
outside
of
secondary
containment.
IFTOA
believes
that
the
facility
should
maintain
a
contingency
plan
to
address
potential
discharges
from
such
pipes
reviewed
and
certified
by
the
PE."
(54)

Clarifications.

Contingency
plan
vis­
a­
vis
Facility
Response
Plans.
Asks
if
we
intend
the
terms
facility
specific
response
plan
and
contingency
plan
as
used
in
the
preamble
to
mean
the
same
thing.
(54)

Costs.
Contingency
planning
is
not
practicable
because
the
costs
are
too
high.
However,
these
commenters
did
not
provide
specific
cost
estimates.
(42,
101,
110,
113,
114,
L15)
We
should
"be
sensitive
to
the
interest
and
concerns"
of
small
businesses
in
developing
the
Phase
Two
rule.
(48)
"It
is
recommended
that
the
Agency's
current
strategy
of
requiring
elementary
contingency
planning
steps
be
continued
for
SPCC
Plans
for
small
facilities."
(101)

Dispersants.
"While
it
is
desirable
to
obtain
approval
from
the
Regional
Administrator
before
using
dispersants,
NJDEPE
is
concerned
about
how
state
approvals
of
such
use
will
be
handled.
NJDEPE's
rules
presently
require
approval
of
either
this
department
or
the
federal
on­
scene
coordinator.
Would
this
approval
be
sufficient
under
this
proposal?"
(147)
186
Disposal
of
recovered
oil
and
other
materials.

Favors
proposal.
"We
strongly
agree
that
provisions
for
waste
disposal
should
be
addressed
in
contingency
plans,
including
provisions
for
the
temporary
storage
of
recovered
oil
and
oily
waste."
(193)

Opposes
proposal.
"The
SPCC
Plan
should
focus
on
spill
control
and
countermeasures
rather
than
disposal
of
discharged
substances,
since
the
disposal
of
recovered
oil,
used
sorbents,
and
other
materials
is
regulated
by
state
regulations,
by
RCRA,
or
existing
federal
regulations."
(L30)

EPA
review
and
approval.
"It
is
not
clear
from
the
proposal
whether
such
a
contingency
plan
must
be
reviewed
and
approved
by
the
Registered
PE
or
the
RA
of
EPA.
Review
by
the
RA
is
duplicative,
time­
consuming,
and
unnecessary."
(54)
Our
proposed
requirement
that
owners
or
operators
submit
contingency
plans
to
the
RA
would
require
the
RA
to
review
and
approve
a
substantial
number
of
plans.
(58)
We
should
delete
the
contingency
plan
submittal
requirement
because
the
RA
already
has
the
authority
under
§112.4
to
call
for
Plans
from
those
facilities
that
may
be
defined
as
"problem
facilities."
(101)
"It
does
not
state
that
it
must
be
provided
to
the
Regional
Administrator
any
more
than
the
SPCC
Plan
must
be
provided.
It
must
be
provided
if
requested
by
the
Regional
Administrator,
but
the
preamble
language
infers
that
submittal
of
every
contingency
plan
to
the
RA
is
automatic
upon
being
developed."
(165,
L15)

Electrical
equipment
facilities.
Questions
whether
we
would
be
able
to
both
review
and
approve
all
submitted
plans
within
an
acceptable
time
frame
and
maintain
program
credibility.
(111)
"It
is
unnecessarily
burdensome
and
expensive,
however,
to
submit
such
plans
to
the
Agency
for
numerous
substations."
(161)
"

Review
times.
"In
addition,
such
a
review
process
could
result
in
project
delays.
If
the
Agency
intends
to
pursue
this
requirement,
the
regulations
should
address
a
reasonable
deadline
(such
as
30
days)
that
the
Agency
would
have
to
review
and
approve
the
contingency
plan."
(90,
161)
We
should
clarify
whether
the
contingency
plan
would
be
due
to
the
RA
within
two
months
of
the
effective
date
of
the
final
rule.
We
should
allow
owners
or
operators
at
least
six
months
to
update
their
existing
SPCC
Plans.
(141)

Financial
responsibility.
The
reference
to
"financial
responsibility
requirements"
is
superfluous.
Equipment,
personnel,
and
other
spill­
related
expenses
are
operating
expenses
for
most
manufacturing
entities,
and
would
impose
no
financial
responsibility.
(162)

Formats.
187
Generic
contingency
plans
(electrical
substations).
"Since
all
substations
are
very
similar
in
design
and
spill
response
would
be
conducted
by
the
same
personnel,
PEO
suggests
that
use
of
more
generic,
area
wide
contingency
plans
be
allowed
for
facilities
such
as
substations."
(41)

HAZWOPER
Plans.
"The
contingency
plan
requirement
should
be
dropped
for
`small
size
facilities'
which
have
a
HAZWOPER
plan
and
trained
response
team."
(62,
152)

RCRA
contingency
plan.
"The
elements
discussed
that
would
make
up
the
Contingency
Plan
are
similar
in
nature
to
those
that
the
RCRA
regulations
require
for
hazardous
storage
facilities.
In
an
effort
to
minimize
redundancy,
the
RCRA
Contingency
Plan
should
be
allowed
to
be
used
in
lieu
of
a
separate
Contingency
Plan
to
satisfy
this
rule."
(87,
186)

Specific
format.
"Finally,
we
recommend
the
oil
spill
response
plan
required
under
40
CFR
112.7(
d)
specify
a
specific
format
for
its
development.
We
recommend
that
the
contents
include
at
least
the
same
requirements
found
in
the
OPA
amendments
to
the
FWPCA."
(171)

Stand
alone
section.

Should
not
stand
alone.
"If
a
discharge
occurs,
personnel
may
need
to
respond
to
operation
and
maintenance
procedures,
as
well
as
responding
to
a
cleanup.
Referring
to
two
sections
for
one
discharge
is
not
effective."
(38)

Should
stand
alone.
"Maintaining
the
contingency
plan
as
a
separate
section
of
the
SPCC
plan
makes
good
operational
sense.
Large
documents
which
contain
non­
essential
information
are
seldom
if
ever
used,
and
difficult
to
use."
(62,
190)

Location
of
contingency
plan.
We
should
require
the
owner
or
operator
to
keep
the
contingency
plan
on­
site
at
the
facility
and
available
for
the
RA's
review
during
normal
working
hours.
This
would
reduce
the
unnecessary
administrative
burden
associated
with
submission
of
the
contingency
plan.
(90)

Mandatory
secondary
containment.
We
should
require
secondary
containment
for
all
facilities
threatening
ground
or
surface
waters.
Contingency
plans
will
not
stop
petroleum
from
reaching
surface
waters
as
effectively
as
"in­
place
properly
designed
and
maintained
secondary
containment
systems."
(111)

PE
certification.
Asks
if
it
is
necessary
for
a
Professional
Engineer
to
certify
a
contingency
plan.
(121)

Practicability.
Our
definition
of
practicable
is
not
specific
enough.
We
should
provide
guidance
on
practicability,
otherwise,
owners
or
operators
may
base
practicability
on
188
the
economics
of
preparing
a
contingency
plan
rather
than
installing
prevention
equipment.
(1153
(1993
commenter))

Scope
of
the
contingency
plan.
"...
EPA
should
make
clear
that
a
contingency
plan
is
required
for
that
portion
of
the
facility
that
is
outside
of
secondary
containment."
(54)

Response:
Additional
information.
We
have
modified
the
1991
proposal
by
withdrawing
proposed
§112.7(
d)(
1).
We
also
have
withdrawn
the
1993
proposal
which
would
have
required
a
response
plan
for
a
facility
lacking
secondary
containment.

Applicability.
Under
the
current
rule,
contingency
planning
is
necessary
whenever
you
determine
that
a
secondary
containment
system
for
any
part
of
the
facility
that
might
be
the
cause
of
a
discharge
as
described
in
§112.1(
b)
is
not
practicable.
This
requirement
applies
whether
the
facility
is
manned
or
unmanned,
urban
or
rural,
and
for
large
and
small
facilities.
Facility
components
that
might
cause
a
discharge
as
described
in
§112.1(
b)
include
containers,
piping,
valves,
or
other
equipment
or
devices.
Contingency
planning
is
necessary
for
all
facilities
to
avert
and
adequately
respond
to
discharges
as
described
in
§112.1(
b)
regardless
of
facility
size,
if
the
facility
lacks
secondary
containment.
It
is
also
necessary
in
areas
historically
not
subject
to
natural
disasters,
because
spills
can
also
be
caused
by
human
error
or
mechanical
failures.

Completely
buried
tanks.
We
note
that
completely
buried
tanks,
as
defined
in
§112.2,
and
connected
underground
piping,
underground
ancillary
equipment,
and
containment
systems
that
are
subject
to
all
of
the
technical
requirements
of
40
CFR
part
280
or
a
State
program
approved
under
40
CFR
part
281
are
not
subject
to
part
112.
40
CFR
112.(
d)(
2)(
i).
Those
tanks,
piping,
and
ancillary
equipment
that
remain
subject
to
the
SPCC
program
are
therefore
subject
to
contingency
planning
requirements
in
the
appropriate
case.

Electrical
equipment.
Any
facility
without
secondary
containment
must
prepare
a
contingency
plan
when
secondary
containment
is
not
practicable.
See
the
discussion
under
§112.7(
d)
in
today's
preamble.
We
disagree
that
the
preamble
language
should
be
construed
as
granting
a
blanket
impracticability
determination
to
any
facility
(including
facilities
with
electrical
equipment).
Such
a
determination
is
a
facility­
specific
one.

FRP
facilities.
In
response
to
comment,
we
have
revised
the
rule
to
exempt
from
the
contingency
planning
requirement
any
facility
which
has
submitted
a
response
plan
under
§112.20
because
such
a
response
plan
is
more
comprehensive
than
a
contingency
plan
following
part
109.

We
disagree
that
facility
response
planning
is
beyond
our
statutory
authority,
since
it
is
a
procedure
or
method
to
remove
discharged
oil.
See
section
311(
j)(
1)(
A)
of
the
CWA.
However,
while
we
disagree
that
such
planning
is
expensive
and
lacking
in
environmental
benefit,
we
agree
that
the
current
contingency
plan
arrangements
which
reference
40
CFR
part
109
should
be
189
sufficient
to
protect
the
environment,
and
that
a
facility
response
plan
as
described
in
§112.20
is
therefore
unnecessary
for
a
facility
that
is
not
otherwise
subject
to
§112.20.
We
agree
with
the
commenter
that
structures
or
equipment
might
achieve
the
same
or
equivalent
protection
as
response
planning
for
some
SPCC
facilities.
Therefore,
we
are
withdrawing
that
part
of
the
1993
proposal
related
to
response
planning
in
proposed
§112.7(
d)(
1),
but
are
retaining
the
current
contingency
planning
provisions,
which
require
a
contingency
plan
following
the
provisions
of
40
CFR
part
109.
We
also
believe
that
response
plans
should
be
reserved
for
higher
risk
facilities,
as
provided
in
§112.
20.

Clarifications.

Contingency
plan
vis­
a­
vis
Facility
Response
Plans.
The
terms
facility
specific
response
plan
(FRP)
and
contingency
plan
have
different
meanings.
The
oil
spill
contingency
plan
is
part
of
the
SPCC
Plan,
required
when
secondary
containment
is
not
practicable
at
a
facility.
The
FRP,
addressed
in
§§
112.20­
21,
is
separate
from
the
SPCC
Plan,
and
is
required
only
for
a
certain
subset
of
SPCC
facilities.

Costs.
We
note
that
we
did
not
finalize
the
1991
or
1993
contingency
planning
proposals.
Thus
there
are
no
new
costs
for
such
planning.

Dispersants.
We
withdrew
the
proposed
reference
to
the
use
of
dispersants
in
§112.7(
d)
in
1993.
Dispersant
use
is
governed
by
subpart
J
of
the
NCP.

EPA
review
and
approval.
We
have
withdrawn
the
proposed
submittal
requirement
because
we
believe
it
is
sufficient
that
the
contingency
plan
be
available
for
on­
site
inspection.
The
contingency
plan
must
be
made
a
part
of
the
SPCC
Plan,
and
therefore,
PE
certification
is
required.
In
certifying
the
SPCC
Plan,
the
PE
attests
that
the
owner's
or
operator's
judgment
of
impracticability
is
correct.

Disposal
of
recovered
oil
and
other
materials.
We
agree
that
we
should
not
require
an
owner
or
operator
to
address
the
disposal
of
recovered
oil
and
other
materials
in
a
facility­
specific
contingency
plan
because
this
discussion
is
already
required
under
§112.7(
a)(
v).

Financial
responsibility.
We
have
deleted
the
proposed
recommendation
concerning
financial
capability
in
making
written
commitments
of
manpower,
equipment,
and
materials
from
the
rules
because
we
do
not
wish
to
confuse
the
regulated
community
by
including
discretionary
requirements
in
a
mandatory
rule.

Formats.
For
§112.7
contingency
planning
requirements,
an
owner
or
operator
may
use
a
contingency
plan
prepared
under
other
State
or
Federal
authority
as
long
as
the
plan
follows
part
109,
or
is
supplemented
so
that
it
meets
all
of
part
109's
requirements.
190
Generic
contingency
plans
(electrical
substations).
We
agree
that
an
owner
or
operator
may
create
a
multi­
facility
contingency
plan.
Such
plan
must
include
all
elements
required
for
individual
contingency
plans.
It
must
also
include
sitespecific
information.
However,
the
site
specific
information
might
be
maintained
in
a
separate
location,
such
as
a
central
office,
or
an
electronic
data
base,
as
long
as
such
information
is
immediately
accessible
to
responders
and
inspectors.
Where
you
place
that
site­
specific
information
is
a
question
of
allowable
formatting,
an
issue
subject
to
RA
discretion.

HAZWOPER
Plans.
The
RA
has
discretion
to
accept
any
format
that
meets
the
requirements
of
40
CFR
part
109.
Where
such
alternate
format
does
not
meet
all
of
part
109's
requirements,
the
owner
or
operator
may
supplement
it
so
that
it
does.

RCRA.
A
contingency
plan
prepared
under
RCRA
rules
might
suffice
for
purposes
of
the
rule
if
the
plan
fulfills
the
requirements
of
part
109,
and
the
PE
certifies
that
such
plan
is
adequate
for
the
facility.
If
the
RCRA
contingency
plan
satisfies
some
but
not
all
SPCC
requirements,
you
must
supplement
it
so
that
it
does.

Specific
format.
It
is
unnecessary
to
specify
a
format
for
a
contingency
plan
because
we
do
not
believe
that
there
is
a
single
format
applicable
to
all
facilities.

Stand
alone
section.
We
have
withdrawn
the
proposed
requirement
that
the
contingency
plan
be
a
stand­
alone
section
of
the
SPCC
Plan.
The
owner
or
operator
has
flexibility
to
determine
where
to
incorporate
the
contingency
plan
within
the
SPCC
Plan.

Location
of
contingency
plan.
Today
we
have
finalized
the
1991
proposal
that
the
Plan
must
be
available
at
the
facility
if
it
is
normally
attended
at
least
four
hours
per
day,
or
at
the
nearest
field
office
if
it
is
not
so
attended.
A
Plan
must
always
be
available
without
advance
notice,
because
an
inspection
might
not
be
scheduled.
You
are
not
required
to
locate
a
Plan
at
an
unattended
facility
because
of
the
difficulty
that
might
ensue
when
emergency
personnel
try
to
find
the
Plan.
However,
you
may
keep
a
Plan
at
an
unattended
facility.
If
you
do
not
locate
the
Plan
at
the
facility,
you
must
locate
it
at
the
nearest
field
office.

Mandatory
secondary
containment.
We
agree
that
an
in­
place,
properly
designed,
and
maintained
secondary
containment
system
is
the
most
effective
way
to
prevent
a
discharge
as
described
in
§112.
1(
b).
However,
for
certain
facilities,
secondary
containment
may
not
be
practicable
because
of
geographic
limitations,
local
zoning
ordinances,
fire
prevention
standards,
or
other
good
engineering
practice
reasons.

Part
109
requirements.
In
following
the
provisions
of
part
109,
you
must
address
the
oil
removal
contingency
planning
criteria
listed
in
40
CFR
109.5
and
ensure
that
all
response
actions
are
coordinated
with
governmental
oil
spill
response
organizations.
191
The
absence
of
secondary
containment
will
place
extreme
importance
on
the
early
detection
of
an
oil
discharge
and
rapid
response
by
the
facility
to
prevent
that
discharge.
Part
109
was
originally
promulgated
to
assist
State
and
local
government
oil
spill
response
agencies
to
prepare
oil
removal
contingency
plans
in
the
inland
response
zone,
where
EPA
provides
the
On­
Scene
Coordinator.
The
basic
criteria
for
contingency
planning
listed
in
§109.5
apply
to
any
SPCC
regulated
facility
that
has
adequately
justified
the
impracticability
of
installing
secondary
containment,
irrespective
of
whether
it
is
a
government
agency
or
the
facility
is
located
in
the
coastal
(U.
S.
Coast
Guard)
or
inland
(EPA)
response
zone.
Because
the
contingency
plan
involves
good
engineering
practice
and
is
technically
a
material
part
of
the
Plan,
PE
certification
is
required.

PE
certification.
The
contingency
plan
is
a
technical
part
of
the
SPCC
Plan
which
must
be
certified
by
a
PE.

Practicability.
We
believe
that
it
may
be
appropriate
for
an
owner
or
operator
to
consider
costs
or
economic
impacts
in
determining
whether
he
can
meet
a
specific
requirement
that
falls
within
the
general
deviation
provision
of
§112.7(
a)(
2).
We
believe
so
because
under
this
section,
the
owner
or
operator
will
still
have
to
utilize
good
engineering
practices
and
come
up
with
an
alternative
that
provides
"equivalent
environmental
protection."
However,
we
believe
that
the
secondary
containment
requirement
in
§112.7(
d)
is
an
important
component
in
preventing
discharges
as
described
in
§112.1(
b)
and
is
environmentally
preferable
to
a
contingency
plan
prepared
under
40
CFR
part
109.
Thus,
we
do
not
believe
it
is
appropriate
to
allow
an
owner
or
operator
to
consider
costs
or
economic
impacts
in
any
determination
as
to
whether
he
can
satisfy
the
secondary
containment
requirement.
Instead,
the
owner
or
operator
may
only
provide
a
contingency
plan
in
his
SPCC
Plan
and
otherwise
comply
with
§112.
7(
d).
Therefore,
the
purpose
of
a
determination
of
impracticability
is
to
examine
whether
space
or
other
geographic
limitations
of
the
facility
would
accommodate
secondary
containment;
whether
local
zoning
ordinances,
fire
prevention
standards,
or
safety
considerations
would
prohibit
the
installation
of
secondary
containment;
or,
if
the
installation
of
secondary
containment
would
defeat
the
goal
of
the
regulation
to
prevent
discharges
as
described
in
§112.1(
b).

Review
of
contingency
plans.
We
note
that
the
preamble
to
the
1993
proposed
rule
(at
58
FR
8841)
suggested
that
response
plans
would
not
have
to
be
submitted
to
the
Regional
Administrator
unless
"otherwise
required
by
the
rest
of
today's
proposed
rule."
However,
proposed
§112.7(
a)(
2)
would
have
required
that
the
owner
or
operator
submit
to
the
Regional
Administrator
any
Plan
containing
a
proposed
deviation,
including
a
deviation
for
the
general
secondary
containment
requirements
in
§112.7(
c).
In
any
case,
we
agree
with
commenters
that
the
contingency
plan
(or
any
other
deviation)
should
not
have
to
be
submitted
to
the
Regional
Administrator
for
his
review
and
approval
because
we
believe
that
it
is
sufficient
that
the
contingency
plan
(or
other
deviation)
be
available
for
on­
site
inspection.
We
have
therefore
withdrawn
that
part
of
the
proposal.
See
also
the
discussion
on
§112.7(
a)(
2).
192
Scope
of
the
contingency
plan.
The
contingency
plan
is
applicable
to
the
entire
facility
because
it
involves
the
capacity
of
the
entire
facility
to
prepare
for
and
respond
to
a
discharge
as
described
in
§112.1(
b).

Small
facilities.
We
disagree
that
contingency
planning
is
too
costly
for
small
facilities.
Such
planning
helps
to
save
money
when
a
discharge
occurs.
The
requirements
for
contingency
planning
are
fewer
than
the
requirements
for
response
planning.
Response
planning
is
required
only
for
higher
storage,
higher
risk
facilities.

Written
commitment.
A
"written
commitment"
of
manpower,
equipment,
and
materials
means
either
a
written
contract
or
other
written
documentation
showing
that
you
have
made
provision
for
those
items
for
response
purposes.
Such
commitment
must
be
shown
by:
the
identification
and
inventory
of
applicable
equipment,
materials,
and
supplies
which
are
available
locally
and
regionally;
an
estimate
of
the
equipment,
materials,
and
supplies
which
would
be
required
to
remove
the
maximum
oil
discharge
to
be
anticipated;
and,
development
of
agreements
and
arrangements
in
advance
of
an
oil
discharge
for
the
acquisition
of
equipment,
materials,
and
supplies
to
be
used
in
responding
to
such
a
discharge.
40
CFR
109.5(
c).

The
commitment
also
involves
making
provisions
for
well
defined
and
specific
actions
to
be
taken
after
discovery
and
notification
of
an
oil
discharge
including:
specification
of
an
oil
discharge
response
operating
team
consisting
of
trained,
prepared,
and
available
operating
personnel;
predesignation
of
a
properly
qualified
oil
discharge
response
coordinator
who
is
charged
with
the
responsibility
and
delegated
commensurate
authority
for
directing
and
coordinating
response
operations
and
who
knows
how
to
request
assistance
from
Federal
authorities
operating
under
current
national
and
regional
contingency
plans;
a
preplanned
location
for
an
oil
discharge
response
operations
center
and
a
reliable
communications
system
for
directing
the
coordinated
overall
response
actions;
provisions
for
varying
degrees
of
response
effort
depending
on
the
severity
of
the
oil
discharge;
and,
specification
of
the
order
of
priority
in
which
the
various
water
uses
are
to
be
protected
where
more
than
one
water
use
may
be
adversely
affected
as
a
result
of
an
oil
discharge
and
where
response
operations
may
not
be
adequate
to
protect
all
uses.
40
CFR
109.5(
d).

X
­
F:
Integrity
and
leak
testing
­
§112.7(
d)

Background:
Section
112.7(
d)
of
the
current
rule
sets
out
requirements
for
a
facility
when
secondary
containment
is
not
practicable.
In
such
cases,
the
owner
or
operator
must
explain
the
impracticability;
provide
a
contingency
plan
following
the
provisions
in
40
CFR
part
109;
and
provide
a
written
commitment
of
manpower,
equipment,
and
materials
to
control
and
remove
any
harmful
quantity
of
discharged
oil.
In
1991,
we
proposed
adding
a
requirement
in
§112.7(
d)
for
the
owner
or
operator
of
a
facility
without
secondary
containment
to
conduct
integrity
tests
of
tanks
at
least
once
every
five
years.
We
also
proposed
adding
a
requirement
for
integrity
and
leak
testing
of
valves
and
piping
at
least
once
a
year.
193
Comments:
Alternatives
to
integrity
testing.

Engineering
evaluation
instead.
Rather
than
requiring
an
owner
or
operator
to
conduct
integrity
tests
of
underground
piping,
we
should
require
an
owner
or
operator
to
conduct
an
"engineering
evaluation"
of
unprotected,
underground
piping
to
test
its
integrity.
(67,
91)

Applicability.

Ancillary
equipment.
"...,
because
spills
and
leaks
most
commonly
occur
due
to
equipment
failures
related
to
piping,
valves,
and
pumps,
ATA
recommends
expanding
the
integrity
test
to
cover
ancillary
equipment.
The
same
5­
year
and
10­
year
testing
schedules
proposed
for
tanks
are
reasonable
for
ancillary
equipment."
(107)

Electrical
equipment.
"...
this
provision
is
impracticable
because
certain
types
of
electrical
equipment,
such
as
underground
transmission
cable
systems,
cannot
be
integrity
tested,
while
ones
that
can
be
tested,
such
as
transformers,
must
be
taken
out
of
service
to
be
tested.
Moreover,
this
requirement
is
unnecessary
because
electrical
equipment
in
service
is
constantly
being
tested
because
the
equipment
will
fail
if
there
is
a
leak."
(74,
125,
156,
158,
183,
189,
192)
It
is
unnecessary
and
inappropriate
to
apply
the
§112.7(
d)
integrity
testing
requirements
to
oil­
filled
equipment,
because
typical
substation
transformers
are
protected
by
alarm
systems
sufficient
to
alert
operators
of
leaks.
Integrity
testing
this
equipment
would
result
in
an
unnecessary
expense.
(158)
"This
is
another
instance
where
a
size
differential
could
be
used
to
exempt
oil­
filled
electrical
equipment
from
these
inappropriate
and
unnecessary
requirements."
(183)

Fixed
aboveground
piping.
Proposed
§112.7(
d)
should
apply
only
to
fixed
aboveground
piping
that
lacks
secondary
containment.
It
appears
that
§112.7(
d)
applies
to
aboveground
and
underground
tanks,
valves,
and
piping;
and
it
is
highly
unlikely
for
buried
tanks,
piping,
or
valves
to
have
secondary
containment.
Further,
proposed
§112.7(
d)
"defeats
the
discretionary
testing
schedule
contained
in
§§
112.
8(
c)(
4)
for
buried
metallic
tanks
and
112.
8(
d)(
4)
for
buried
piping."
(102)

Flowlines
and
gathering
lines.
"Further,
the
alternate
to
40
CFR
section
112.7(
c)
requires
flow
lines
testing.
The
pressure
test
provision
offer
little
advantage
over
normal
flowline
pressure,
which
is
present
at
all
times.
Typically,
flowline
leaks
are
small
and
routine
inspection
at
road
crossings
provides
sufficient
protection
from
oil
entering
Waters
of
the
U.
S.
However,
the
voluntary
Contingency
Plan
requirement
provides
added
protection."
(110)
The
required
annual
pressure
testing
of
flowlines
and
gathering
systems
would
be
costly
for
small
operators.
We
should
exclude
flowlines
and
gathering
systems
from
the
§112.7(
d)
testing
provisions.
(28,
31,
101,165,
L15).
194
Impracticality.
We
should
not
require
annual
integrity
leak
testing
of
tanks
where
installation
of
secondary
containment
is
impractical.
Monthly
visual
inspection
of
tanks,
valves,
and
aboveground
piping
provides
adequate
protection
to
the
environment.
(1155
(1993
commenter))

Phase­
in.
We
should
require
tanks
subject
to
§112.7(
d)
to
comply
with
the
provisions
within
five
years
of
the
promulgation
date
of
the
final
rule
and
every
five
years
thereafter.
(125)

Production
facilities.
We
should
clarify
whether
secondary
containment
is
inapplicable
for
offshore
and
coastal
production
facilities,
and
therefore,
whether
the
proposed
integrity
testing
requirements
are
necessary
at
such
facilities.
"In
all
other
cases,"
the
integrity
testing
requirements
should
not
be
applicable
to
the
production
industry.
(1199
(1993
commenter))

Small
facilities.

Supports
testing
requirements.
"The
testing
of
tanks
for
integrity
is
needed.
While
most
large
corporations
perform
testing
at
some
frequency,
most
smaller
businesses
do
not.
Exemptions
because
of
size
or
quantity
of
oil
stored
should
not
be
granted
because
the
smaller
facilities
generally
are
more
in
need
of
testing."
(3,
4,
27,
95)

Opposes
testing
requirements.
"EPA
should
make
a
distinction
between
large
and
small
facilities,
and
should
require
integrity
testing
only
on
larger
tanks
such
as
those
commonly
located
at
complicated
fuel
distribution
sites,
commonly
known
as
tank
farms.
Facilities
which
are
primarily
engaged
in
vehicle
refueling
operate
above
ground
tanks
which
typically
hold
significantly
less
than
that
found
at
tank
farms
are
suitable
for
visual
inspections.
EPA
should
realize
that
presently,
there
exists
a
limited
amount
of
organizations
which
perform
integrity
tests
on
above
ground
tanks.
If
EPA
were
to
promulgate
an
integrity
test
requirement
on
all
aboveground
tanks,
many
trucking
facilities
will
find
it
difficult
and
expensive
to
identify
appropriate
testing
agents."
(53,
70)
Proposed
§112.7(
d)
integrity
testing
requirements
would
be
burdensome
for
small
remote
facilities.
We
should
require
integrity
testing
only
at
a
facility
with
a
storage
capacity
greater
than
42,000
gallons
and
without
the
structures
or
equipment
listed
in
proposed
§112.7(
c).
(78,
145,
L3)
We
should
require
integrity
testing
for
facilities
with
a
storage
capacity
greater
than
100,000
gallons,
and
testing
of
valves
and
piping
located
directly
above
or
on
a
pervious
surface
of
such
tanks.
(90,1137
(1993
commenter))
The
§112.7(
d)
requirement
should
apply
only
to
tanks
with
more
than
660
gallons,
because
the
costs
of
integrity
testing
smaller
tanks
outweigh
the
benefits.
(125)
The
§112.9(
d)
provisions
provide
adequate
environmental
protection
for
small
facilities.
(145)

Tank
failure.
"Integrity
testing
at
other
than
ten
(10)
year
intervals
should
only
be
required
if
a
tank
failure
has
occurred
within
the
last
5
years
or
the
tank
is
195
used
to
store
materials
that
are
corrosive
to
the
tank
material.
The
small
tanks
at
E&
P
operations
are
not
likely
to
be
susceptible
to
conditions
requiring
the
five
year
inspection
regimen."
(114)

Underground
cable
systems.
Current
technology
does
not
allow
an
owner
or
operator
to
apply
the
secondary
containment,
inspection,
and
integrity
testing
requirements
of
the
SPCC
program
to
underground
cable
systems.
(92,
98,
125)
Proposed
§112.7(
d)
is
inappropriate
for
underground
cable
systems
because
there
is
no
efficient
system
for
integrity
testing
miles
of
interconnected
piping.
An
owner
or
operator
must
keep
underground
cable
systems
in
service.
It
is
impossible
for
an
owner
or
operator
to
develop
a
site­
specific
contingency
plan
for
underground
cable,
since
such
systems
cover
large
geographical
areas.
(125)
We
should
not
require
an
owner
or
operator
to
prepare
a
Plan
for
or
integrity
test
cable
systems.
(164,
165)

Unprotected
underground
piping.
We
should
limit
annual
integrity
and
leak
test
requirements
to
unprotected
underground
piping.
(167)

Within
structures,
small
tanks.
"We
propose
an
exemption
for
integrity
testing
of
all
tanks
which:
are
contained
within
a
building
or
have
a
maximum
capacity
of
less
than
2000
gallons;
have
all
sides
visible,
and;
which
are
visually
inspected
(along
with
any
associated
piping
and
ancillary
equipment)
at
least
monthly."
(54,
71,
78,
90,
101,
109,
110,
162,
167,
175)

Cost.
Integrity
testing
is
too
costly.
(28,
31,
54,
57,
58,
90,
102,
110;
1137,1145
(1993
commenters).)
The
proposed
requirement
to
test
tanks
without
secondary
containment
annually
would
be
costly
and
would
restrict
the
owner's
or
operator's
ability
to
conduct
necessary
inventories
and
to
"meet
supply
and
demand
needs."
It
would
be
impossible
for
the
facility
to
operate
if
all
tanks
were
taken
out
of
service
for
testing
every
year.
(25)
We
did
not
adequately
consider
the
costs
associated
with
the
integrity
testing
for
high
pour
point
(e.
g.,
60
"

F)
bulk
storage
tanks,
because
proposed
§112.7(
d)
would
require
an
owner
or
operator
to
completely
drain
and
clean
a
tank.
Such
integrity
tests
would
pose
an
unnecessary
cost
given
the
low
risk
of
spills
from
such
tanks.
(90)
We
did
not
consider
the
cost
of
integrity
testing
substations
and
other
oil­
filled
equipment
in
our
economic
impact
analysis
for
the
rulemaking.
Such
testing
is
impractical
since
owners
or
operators
would
have
to
test
individual
equipment
pieces.
(L2)

Discretionary
testing.
We
should
allow
an
owner
or
operator
to
determine
the
integrity
of
aboveground
piping
through
frequent
visual
inspection
and
observation
of
the
product
flowing
through
the
line.
We
should
allow
an
owner
or
operator
to
conduct
visual
inspections
to
comply
with
the
§112.7(
d)
integrity
testing
requirement.
(54)
The
requirement
to
conduct
integrity
testing
applies
to
aboveground
and
buried
tanks,
piping,
and
valves
should
be
discretionary.
If
the
requirement
were
discretionary,
the
owner
or
operator
could
set
a
testing
frequency
based
on
facility­
specific
factors
such
as
the
facility's
age,
soil
corrosiveness,
and
corrosion
protection.
Such
a
discretionary
196
provision
"defeats
the
discretionary
metallic
testing
scheduled
contained
in
§112.
8(
c)(
4)
for
buried
metallic
tanks
and
§112.
8(
d)(
4)
for
buried
piping."
(102)

Frequency
of
testing.

Support
for
proposal.
General
support
for
our
proposal
to
specify
time
periods.
(148,
L1)
Support
for
proposal
to
perform
integrity
testing
of
tanks
once
every
five
years
at
facilities
without
secondary
containment.
(95,
101,
102,
L1,
L2)
Support
for
testing
valves
and
piping
once
a
year
at
such
facilities.
(80,
117)
Support
for
integrity
testing
for
cathodically
protected
piping
every
five
years
(167)
and
at
the
time
of
installation,
modification,
repair,
and
relocation
(67).

Opposition
to
proposal.
We
should
not
require
integrity
testing
of
tanks
every
five
years.
(57,
78,
90,
101,
109,
128,
L2,
(1137,
1145,
1146,
1199
(1993
commenters))
Imposing
these
specific
time
periods
is
unnecessary
and
would
provide
"no
improvement
in
the
quality
of
SPCC
plans."
(155)

Cost.
The
proposed
requirement
to
test
tanks
with
secondary
containment
every
five
years
would
be
costly
and
would
obstruct
handling
necessary
inventories.
The
proposed
requirement
would
reduce
the
commenter's
facility's
ability
to
meet
supply
and
demand,
and
it
would
be
impossible
to
operate
the
facility
if
all
tanks
were
out
of
service
for
testing
every
year.
(25)

Excessive.
"This
requirement
is
not
realistic
for
the
oil
and
gas
industry
in
Appalachia.
It
is
recommended
that
the
current
language
from
§112.7(
e)(
5)
be
retained."
(54,
67,
91,
95,
101,
102,
109,
167,
175,
L2;
(1137,
1145,
1146,
1199
(1993
commenters)).
New
tanks
need
less
inspections
than
older
ones,
and
we
should
only
require
an
owner
or
operator
to
test
a
tank
every
five
years
after
the
first
fifteen
years
of
the
tank's
manufacturing
date.
(1165
(1993
commenter))
We
should
only
require
integrity
testing
less
frequently
than
every
10
years
only
if
a
tank
failure
has
occurred
within
the
last
five
years,
or
if
the
tank
contains
corrosive
materials.
Small
tanks
at
exploration
and
production
(E&
P)
operation
sites
are
unlikely
to
require
integrity
testing
every
five
years.
We
should
require
integrity
testing
of
pipes,
valves,
and
fittings
when
corrosion
or
leakage
has
occurred
or
is
"potentially
severe."
(114)
We
should
only
require
an
owner
or
operator
to
test
valves
and
piping
without
secondary
containment
once
every
five
years,
and
we
should
require
an
owner
or
operator
to
include
in
the
Plan
a
schedule
of
visual
inspections
for
such
valves
and
piping.
(95,
L2)
Such
an
approach
would
reduce
the
amount
of
waste
generated
by
integrity
testing
and
provide
a
reasonable
integrity
testing
schedule.
(95)

Maintenance
instead.
Routine
inspection
and
maintenance
of
aboveground
storage
tanks
and
associated
pipes,
valves,
and
pumps
is
sufficient
to
eliminate
the
potential
of
a
significant
spill.
We
should
require
integrity
testing
only
when
the
owner
or
operator
detects
something
that
may
lead
to
a
discharge.
Inspections
allow
an
owner
or
operator
to
determine
whether
maintenance
and
197
repairs
are
required
to
prevent
a
discharge.
(54,
71,
78,
90,
101,
109,
110,
162,
167,
175)

Material
repairs.
Integrity
testing
is
necessary
only
after
material
repairs.
(78)

Mines.
"For
some
small
mining
facilities,
these
testing
requirements
would
be
overly
burdensome
and
quite
expensive....
EPA
should
take
into
account
the
quantity
of
oil
stored
at
a
facility,
and
allow
small
facilities,
with
secondary
containment,
the
right
to
inspect
and
monitor
at
the
operator
discretion,
in
accordance
with
good
engineering
practice."
(10)

Need
for
testing.
We
should
develop
an
"administrative
record"
to
determine
the
need
for
integrity
testing.
We
should
not
require
an
integrity
testing
schedule
in
Phase
One
without
stating
what
types
of
tests
meet
"statutory
objectives."
(75)

Negative
or
no
environmental
impact.
Integrity
testing
can
negatively
impact
the
environment.
(90,
95)
Annual
testing
would
not
significantly
increase
the
level
of
environmental
protection.
(L2)

System
failures.
Integrity
testing
may
exacerbate
the
probability
of
system
failures.
(67,
91,
1146,
1155
(1993
commenters))

Tank
construction.
We
should
base
the
frequency
of
integrity
testing
on
such
factors
as
the
tank
construction
material
and
the
nature
of
the
material
in
the
tank.
(190)

Unnecessary.
"This
testing
requirement
would
be
costly
to
impose
and
lacks
justification.
Tanks
with
and
without
secondary
containment
deteriorate
at
the
same
rate
and
there
is
no
reason
to
impose
different
testing
requirements.
The
lack
of
secondary
containment
should
be
compensated
for
by
site­
specific
contingency
plans."
(57)

Weekly
inspections
instead.
Instead
of
requiring
annual
integrity
and
leak
testing,
we
should
allow
an
owner
or
operator
to
conduct
weekly
inspections
for
oil
leaks
or
spills
during
normal
production
facility
operating
conditions.
There
is
a
low
risk
of
significant
spills
at
production
facility
oil
gathering
systems
because
individual
wells
are
located
in
a
central
processing
storage
facility.
(1145
(1993
comment))

More
frequent
testing.
We
should
permit
more
frequent
inspection
and
monitoring
than
the
rule
requires.
(87)

Guidance.
We
should
set
guidelines
and
recommendations
in
§112.7(
d)
for
inspections
and
testing
procedures
and
include
proven
and
acceptable
test
methods
in
the
regulation.
We
should
include
in
§112.7(
d)
specific
integrity
testing
procedures
required
for
electrical
equipment.
(27,
80,
L2)
198
Integrity
testing.
We
should
revise
§112.7(
d)
to
define
integrity
testing.
(70)
We
did
not
define
periodic
integrity
testing
in
the
proposed
rule,
noting
that
we
define
the
term
in
current
§112.7(
e)(
2)(
vi).
(1149
(1993
comment))

Methods
of
testing.

Acoustic
emission
testing.
We
should
allow
for
acoustic
emission
testing
instead
of
hydrostatic
testing
as
covered
by
API
Standard
653.
The
tests
are
equally
effective,
but
acoustic
emission
testing
reduces
wastewater
production.
(1135
(1993
comment))

API
standards.
"In
lieu
of
frequent
`integrity
testing,
'
we
suggest
that
the
EPA
adopt
the
inspection
portion
of
API
653,
which
allows
up
to
20
years
between
inspections.
Integrity
testing
should
be
defined
as
the
evaluation
of
a
tank
for
serviceability.
Short
of
a
hydrostatic
test,
comprehensive
tank
inspection
is
the
only
method
to
evaluate
the
serviceability
of
a
tank.
The
tank
inspection
method
presented
in
API
653
details
the
tank
components
that
should
be
examined
and
appropriate
examination
methods."
(1145,
1149
(1993
commenters))

Hydrostatic
testing.
We
should
allow
an
owner
or
operator
to
supplement
hydrostatic
testing
with
other
inspection
techniques
while
the
tanks
are
in
service
and
not
being
tested.
This
would
allow
an
owner
or
operator
to
schedule
tank
outages
when
it
is
most
convenient.
(25)

"No
appropriate
technology."
There
is
no
appropriate
technology
for
testing
fiberglass
tanks
or
aboveground
storage
tanks.
(62)

Pressure
testing.
Pressure
testing
could
perforate
a
weakened
section
of
piping,
and
compel
an
owner
or
operator
to
isolate
and
repair
the
section
to
avoid
a
corrosionrelated
leak.
A
corrosion­
related
leak
could
easily
develop
the
day
after
the
owner
or
operator
performs
pressure
testing.
(28,
31,
101,
165,
L15)
Frequent
pressure
testing
of
buried
tanks
and
piping
will
create
­­
not
prevent
­­
pollution,
since
owners
or
operators
must
conduct
pressure
testing
with
the
oil
contained
in
the
system
or
must
drain
the
oil
and
replace
it
with
water.
Pressure
testing
generates
solid
wastes,
and
that
owners
or
operators
must
treat
and
dispose
of
the
oily
waste.
(102)
Pressure
testing
of
tanks,
valves,
and
equipment
can
weaken
the
integrity
of
a
steel
tank
and
contribute
to
failures
of
such
tanks,
valves,
and
equipment.
(128)

Reference
to
§112.7(
c).
Our
cross­
reference
to
§112.7(
c)
is
unclear.
It
is
unclear
whether
the
§112.7(
c)
reference
refers
to
the
existing
or
the
proposed
rule.
Proposed
§112.7(
d)
integrity
testing
requirement
appears
to
refer
only
to
tank
batteries
with
dikes,
berms,
or
retaining
walls
sufficiently
impervious
to
contain
spilled
oil.
(955
(1993
commenter))

Visual
inspection.
199
Frequency.

Weekly
inspection.
We
should
allow
an
owner
or
operator
to
conduct
daily
or
weekly
visual
inspections
of
valves
and
pipes.
(1145,1199
(1993
commenters))

Monthly
inspection.
We
should
require
an
owner
or
operator
to
conduct
a
visual
inspection
of
valves
and
aboveground
piping
at
least
once
a
month.
(67,
91,
167)

Periodic
inspection.
"To
require
annual
integrity
and
leak
testing
of
aboveground
piping
and
valves
is
unrealistic
and
could
exacerbate
the
probability
of
or
initiate
system
failures.
The
requirement
should
read
"visually
inspect
valves
and
aboveground
piping
periodically
and
conduct
an
engineering
evaluation
of
unprotected
underground
piping
once
every
five
years."
(67,
101,
128,
167,175;
1146
(1993
commenter)).
We
should
require
periodic
visual
examinations
similar
to
the
examinations
proposed
under
§112.9(
e).
(101)

Internal
and
external
inspection.
We
should
clarify
whether
a
visual
inspection
must
be
both
internal
and
external.
(76)

Supplement
to
inspections.
An
owner
or
operator
should
supplement
integrity
testing
with
visual
inspections
(95,
102)
and
recordkeeping
(128).
We
should
supplement
visual
inspections
of
aboveground
valves
and
piping
with
a
five­
year
integrity
testing
schedule.
(175)

Response:
Support
for
proposal.
We
appreciate
commenter
support.

Applicability.
Integrity
testing
is
essential
for
all
aboveground
containers
to
help
prevent
discharges.
Testing
will
show
whether
corrosion
has
reached
a
point
where
repairs
or
replacement
of
the
container
is
needed.
Therefore,
it
must
apply
to
large
and
small
containers,
containers
on
and
off
the
ground
wherever
located,
and
to
containers
storing
any
type
of
oil.
From
all
of
these
containers
there
exists
the
possibility
of
discharge.
We
agree
that
integrity
testing
of
aboveground
piping
should
be
discretionary
when
the
facility
has
secondary
containment
which
would
contain
a
discharge
from
such
piping.
Integrity
and
leak
testing
requirements
are
also
applicable
for
containers
and
valves
and
piping
that
are
entirely
within
buildings,
or
within
mines,
because
in
either
case,
such
containers,
or
valves
and
piping
may
become
the
source
of
a
discharge
as
described
in
§112.1(
b).
We
have
revised
the
rule
to
reflect
that
the
requirement
applies
only
to
onshore
and
offshore
bulk
storage
facilities.
Therefore,
a
facility
with
only
oil­
filled
electrical,
operating,
or
manufacturing
equipment
need
not
conduct
such
testing.
We
disagree
that
testing
of
valves,
gathering
lines,
and
flowlines
would
be
prohibitively
costly.
In
1991,
we
estimated
tank
integrity
testing
and
leak
testing
costs
of
buried
piping.
We
estimated
the
costs
as
$465
per
tank,
$155
for
equipment,
and
$310
for
installation.
Small
facilities
were
assumed
to
have
no
buried
piping.
Medium
sized
facilities
were
assumed
to
bear
first
year
costs
for
tank
installation
and
testing
of
$4,704
and
subsequent
year
costs
of
$1,449.
Large
facilities
were
assumed
to
incur
a
first
year
200
cost
of
$11,313,
and
subsequent
year
costs
of
$3,519.
We
believe
that
this
provision
represents
a
negligible
additional
burden
because
most
facilities
are
already
testing
such
valves
and
gathering
lines
according
to
industry
standards
as
a
matter
of
good
engineering
practice.
We
believe
that
if
such
testing
is
done
in
accordance
with
industry
standards,
costs
will
be
minimized
because
such
standards
will
likely
include
options
appropriate
to
the
equipment
tested
at
a
reasonable
cost.

We
decline
to
exclude
from
§112.7(
d)
all
tanks
that
are
less
than
15
years
old,
since
the
corrosion
and
discharge
rates
of
one
container
will
differ
from
the
next.
We
also
decline
to
require
integrity
testing
only
when
the
owner
or
operator
determines
that
there
is
a
risk
of
discharge,
since
that
standard
is
not
objective.
We
also
disagree
that
we
should
only
require
owners
or
operators
to
integrity
test
valves
and
piping
when
corrosion
or
leakage
has
occurred
or
is
potentially
severe
because
it
is
inappropriate
to
require
a
test
only
when
the
system
or
equipment
shows
signs
of
potential
failure.
The
idea
of
testing
is
to
prevent
such
corrosion
or
leakage.
Likewise,
a
weekly
inspection
for
leaks
is
not
the
equivalent
of
conducting
integrity
tests.
Visual
inspection
must
be
combined
with
some
other
technique.

Electrical
equipment.
Because
electrical,
operating,
manufacturing
equipment
are
not
bulk
storage
containers,
the
requirement
is
inapplicable
to
those
devices
or
equipment.
56
FR
54623.
Also,
as
noted
by
commenters,
methods
may
not
exist
for
integrity
testing
of
such
devices
or
equipment.

Fixed
aboveground
piping.
Section
112.7(
d)
applies
both
to
completely
buried
and
aboveground
tanks,
valves,
and
piping,
including
gathering
lines
and
flowlines.
There
is
no
conflict
with
either
§112.8(
c)(
4)
or
(d)(
4).
Section
112.8(
c)(
4)
provides
for
"regular"
testing
of
completely
buried
tanks.
Section
112.8(
d)(
4)
provides
for
"regular"
inspection
of
aboveground
valves,
piping,
and
appurtenances,
and
integrity
and
leak
testing
of
buried
piping
at
the
time
of
installation,
modification,
construction,
relocation,
or
replacement.
Section
112.7(
d)
provides
for
"periodic"
integrity
testing,
and
"periodic"
integrity
and
leak
testing.
Either
"periodic"
or
"regular"
testing
should
be
conducted
according
to
industry
standards.
Thus,
there
is
no
conflict
between
the
rule
provisions.

Impracticality.
Integrity
testing
under
§112.7(
d)
must
be
performed
if
the
facility
lacks
secondary
containment.
You
have
discretion
as
to
the
method
of
testing,
but
it
must
be
performed
if
it
is
possible
to
do
so.
If
it
is
impossible,
then
the
owner
or
operator
must
explain
his
reasons
for
nonconformance
with
the
requirement,
and
provide
equivalent
environmental
protection
by
some
other
means.

Phase­
in.
We
disagree
that
there
should
be
a
phase­
in
period.
We
believe
that
the
time
allowed
in
§112.3
for
Plan
amendment
and
implementation
allows
ample
time
for
both
existing
and
future
facilities
to
comply
with
the
changes
in
the
rule.
201
Underground
cable
systems.
Because
electrical,
operating,
manufacturing
equipment
are
not
bulk
storage
containers,
the
requirement
is
inapplicable
to
those
devices
or
equipment.
56
FR
54623.
Also,
as
noted
by
commenters,
methods
may
not
exist
for
integrity
testing
of
such
devices
or
equipment.

Unprotected
underground
piping.
We
do
not
require
periodic
integrity
testing
for
underground
piping,
since
uncovering
buried
piping
may
present
an
undue
hazard.
Integrity
and
leak
testing
must
be
conducted
when
buried
piping
is
installed,
modified,
constructed,
relocated,
or
replaced.
For
comments
on
integrity
testing
requirements
for
cathodically
protected
piping
and
unprotected
underground
piping,
see
the
comments
on
§112.8(
c)(
4)
and
(d)(
1)
in
today's
preamble.

Costs.
We
disagree
that
integrity
testing
is
too
costly
because
industry
standards
will
likely
incorporate
options
appropriate
to
the
equipment
at
reasonable
cost.
It
may
help
save
the
owner
or
operator
money
by
preventing
a
discharge
as
described
in
§112.1(
b).
In
1991,
we
estimated
tank
integrity
testing
and
leak
testing
costs
of
buried
piping.
We
estimated
the
costs
as
$465
per
tank,
equipment
of
$155,
and
installation
costs
of
$310
per
tank.
Small
facilities
were
assumed
to
have
no
buried
piping.
Medium
sized
facilities
were
assumed
to
bear
first
year
costs
for
tank
installation
and
testing
of
$4,704
and
subsequent
year
costs
of
$1,449.
Large
facilities
were
assumed
to
incur
a
first
year
cost
of
$11,313,
and
subsequent
year
costs
of
$3,519.
We
assume
that
this
provision
represents
a
negligible
additional
burden
because
most
facilities
are
already
testing
such
valves
and
gathering
lines
according
to
industry
standards
as
a
matter
of
good
engineering
practice.

Frequency
of
testing.
We
have
modified
our
proposal
in
response
to
comments.
We
require
such
testing
on
a
periodic
basis
instead
of
at
a
prescribed
frequency,
both
for
containers
and
for
valves
and
piping.
"Periodic"
testing
means
testing
according
to
a
regular
schedule
consistent
with
accepted
industry
standards.
We
believe
that
use
of
industry
standards,
which
change
over
time,
will
prove
more
feasible
than
providing
a
specific
and
unchanging
regulatory
requirement.
As
required
by
§112.8(
c)(
6),
integrity
testing
of
containers
must
be
accomplished
by
a
combination
of
visual
testing
and
some
other
technique.

We
disagree
that
required
integrity
testing
may
force
an
owner
or
operator
to
shut
down
the
facility
or
its
systems.
Because
such
testing
is
performed
on
a
periodic
or
scheduled
basis,
the
owner
or
operator
has
discretion
as
to
the
schedule
to
keep
the
facility
open
as
much
as
possible.

Integrity
and
leak
testing.
In
response
to
a
commenter
who
asked
for
a
clarification
of
integrity
testing,
"integrity
testing"
is
any
means
to
measure
the
strength
(structural
soundness)
of
the
container
shell,
bottom,
and/
or
floor
to
contain
oil
and
may
include
leak
testing
to
determine
whether
the
container
will
discharge
oil.
Facility
components
that
might
cause
a
discharge
as
described
in
§112.1(
b)
include
containers,
piping,
valves,
or
other
equipment
or
devices.
Integrity
testing
includes,
but
is
not
limited
to,
202
testing
foundations
and
supports
of
containers.
Its
scope
includes
both
the
inside
and
outside
of
the
container.
It
also
includes
frequent
observation
of
the
outside
of
the
container
for
signs
of
deterioration,
leaks,
or
accumulation
of
oil
inside
diked
areas.
Such
testing
is
also
applicable
to
valves
and
piping.
See
API
Standard
653
for
further
information
on
this
term.

Leak
testing
for
purposes
of
the
rule
is
testing
to
determine
the
liquid
tightness
of
valves
and
piping
and
whether
they
may
discharge
oil.
Facilities
that
store
oil,
whether
they
are
mines
or
other
businesses,
are
required
to
employ
integrity
testing
for
their
bulk
storage
containers,
and
integrity
and
leak
testing
for
their
valves
and
piping,
to
help
prevent
discharges.
Containers
that
do
not
store
oil,
but
merely
use
oil,
are
not
subject
to
the
requirement.

Methods
of
testing.
We
do
not
prescribe
the
method
of
testing,
except
to
require
that
visual
inspection
must
be
combined
with
some
other
technique.
We
agree
that
an
owner
or
operator
may
supplement
hydrostatic
testing
with
other
inspection
techniques
while
the
tanks
are
in
service
and
not
being
tested.

We
disagree
that
visual
inspection
and
nondestructive
shell
thickness
testing
are
insufficient.
Such
testing
should
give
the
owner
or
operator
an
indication
of
the
container's
integrity.

We
disagree
that
an
"engineering
evaluation"
of
unprotected,
underground
piping
is
acceptable
in
lieu
of
an
integrity
and
leak
test
because
such
evaluation
may
not
provide
equivalent
environmental
protection
as
integrity
and
leak
testing
of
valves
and
piping.
Likewise,
a
"routine
inspection"
of
flowlines
does
not
rise
to
the
level
of
integrity
and
leak
testing.

We
disagree
that
integrity
testing
would
require
an
owner
or
operator
to
completely
drain
and
clean
high
pour
point
bulk
storage
containers.
Testing
may
be
possible
without
such
drainage,
either
by
using
a
particular
method,
for
example,
a
robot,
or
performing
such
testing
during
regularly
scheduled
maintenance.

We
also
disagree
that
integrity
testing
will
exacerbate
the
probability
of
system
failures
or
negatively
impact
the
environment.
Integrity
testing
is
a
non­
destructive
type
of
testing
that
should
not
affect
system
failures.
Its
only
effect
on
the
environment
should
be
a
positive
one,
to
help
prevent
a
discharge
as
described
in
§112.1(
b).

An
owner
or
operator
must
consider
the
tank
design
and
its
construction
material
when
determining
an
appropriate
testing
schedule
and
method,
and
may
determine
a
periodic
testing
schedule
and
method
based
on
good
engineering
practice,
relevant
industry
standards,
and
optimal
use
of
facility
resources.
The
owner
or
operator
must
also
consider
factors
such
as
the
potential
for
tank
failure,
tank
design,
and
tank
material
when
determining
an
appropriate
testing
schedule
and
method.
Among
these
factors
should
be
how
the
material
stored
effects
the
structural
integrity
of
the
tank.
We
disagree
with
the
commenter
who
stated
that
integrity
testing
is
necessary
only
after
203
material
repairs.
A
discharge
may
occur
at
any
time,
regardless
of
whether
an
owner
or
operator
has
conducted
repairs.

Guidance.
Due
to
rapidly
changing
technology,
we
cannot
list
all
types
of
integrity
testing
methods.
There
is
no
single
operational
standard
we
can
prescribe
for
all
non­
transportation­
related
facilities.
However,
we
include
industry
standards
in
the
preamble
to
today's
final
rule
to
assist
the
reader.
See
the
discussion
in
§§
112.7(
d)
and
112.8(
c)(
6).
We
also
list
organizations
that
help
to
formulate
industry
standards
in
section
IV.
D
of
today's
preamble.

Pressure
testing.
We
do
not
require
pressure
testing.
Therefore,
none
of
the
problems
cited
with
such
testing
are
relevant.

Reference
to
§112.7(
c).
The
reference
in
proposed
§112.7(
d)
was
to
proposed
§112.7(
c).
Section
§112.7(
d)
integrity
testing
and
integrity
and
leak
testing
requirements
apply
to
any
facility
which
lacks
secondary
containment.

Visual
inspection.
The
rule
requires
visual
testing
in
conjunction
with
another
method
of
testing,
because
visual
testing
alone
is
normally
insufficient
to
measure
the
integrity
of
a
container.
Visual
testing
alone
might
not
detect
problems
which
could
lead
to
container
failure.
For
example,
studies
of
the
1988
Ashland
oil
spill
suggest
that
the
tank
collapse
resulted
from
a
brittle
fracture
in
the
shell
of
the
tank.
Adequate
fracture
toughness
of
the
base
metal
of
existing
tanks
is
an
important
consideration
in
discharge
prevention,
especially
in
cold
weather.
Although
no
definitive
non­
destructive
test
exists
for
testing
fracture
toughness,
had
the
tank
been
evaluated
for
brittle
fracture,
for
example
under
API
standard
653,
and
had
the
evaluation
shown
that
the
tank
was
at
risk
for
brittle
fracture,
the
owner
or
operator
could
have
taken
measures
to
repair
or
modify
the
tank's
operation
to
prevent
failure.

For
certain
smaller
shop­
built
containers
in
which
internal
corrosion
poses
minimal
risk
of
failure;
which
are
inspected
at
least
monthly;
and,
for
which
all
sides
are
visible
(i.
e.,
the
container
has
no
contact
with
the
ground),
visual
inspection
alone
might
suffice,
subject
to
good
engineering
practice.
In
such
case
the
owner
or
operator
must
explain
in
the
Plan
why
visual
integrity
testing
alone
is
sufficient,
and
provide
equivalent
environmental
protection.
40
CFR
112.7(
a)(
2).
However,
containers
which
are
in
contact
with
the
ground
must
be
evaluated
for
integrity
in
accordance
with
industry
standards
and
good
engineering
practice.

X
­
G:
Inspections,
tests,
and
records
­
§112.7(
e)

Background:
Under
§112.7(
e)(
8)
of
the
current
rule,
an
owner
or
operator
must
maintain
inspection
records
as
part
of
an
SPCC
Plan
for
three
years.
In
§112.7(
e)
of
the
1991
proposed
rule,
we
proposed
to
extend
the
period
for
retaining
records
of
inspections,
test
results,
and
written
procedures
from
three
to
five
years.
We
proposed
this
extension
to
be
consistent
with
the
Federal
statute
of
limitations
on
assessing
civil
penalties
for
violating
the
SPCC
rule.
We
also
proposed
that
these
records
be
204
maintained
with
an
SPCC
Plan,
and
not
as
part
of
an
SPCC
Plan.
In
1997,
we
proposed
to
retain
the
three­
year
record
retention
standard.

Comments:
Editorial
suggestion.
In
the
first
sentence
of
§112.7(
e),
we
should
change
the
word
shall
to
must.
(121)

Form
of
records.
"...
written
procedures
for
testing
only
should
be
omitted
from
the
proposed
rule."
Believes
that
"written
procedures
for
testing
can
be
quite
lengthy
and
would
have
meaning
to
the
tester
only."
(37)
40
CFR
part
112
should
include
the
testing
required
by
40
CFR
part
280.
(47)

Date.
Each
inspection
and
test
report
should
be
dated.
(47)

Electronic
format.
"Using
electronic
media
for
the
storage
and
retrieval
of
standard
operating
practices,
inspection
protocols,
testing
procedures,
and
maintenance
records
is
becoming
commonplace
in
industry.
BP
requests
that
language
be
inserted
in
this
section
to
allow
the
use
of
computers
or
other
electronic
devices
for
the
purpose
of
satisfying
this
section."
(96)

Repairs
and
training.
In
§112.7(
e),
we
should
require
owners
or
operators
to
keep
records
and
tests
of
all
major
repairs
and
of
employee
training,
in
addition
to
written
procedures
and
records
of
inspections
and
tests.
(147)

Maintenance
with
Plan.

Accessible
location.
"FINA
proposes
that
the
records
be
maintained
at
the
facility
or
at
an
alternate
location
accessible
within
24
hours."
(25,
37,
38,
47,
67,
83,
187)

Principal
place
of
business.
Owners
or
operators
should
maintain
records
for
the
most
current
three
years
with
the
Plan,
and
should
maintain
records
for
the
remaining
two
years
at
the
facility's
principal
place
of
business.
(54)

Required
inspections
and
tests.
"It
would
be
helpful
if
EPA
could
include
a
list
of
all
inspections
and
tests
required
by
this
part."
(16)

Time
period.

Opposes
5­
year
proposal.
(22,
33,
67,
101,
113,
167,
181,
187)
An
obligation
to
maintain
records
for
five
years
places
an
undue
administrative
burden
on
facility
owners
or
operators.
(45,
113,
181)
A
five­
year
record
retention
provision
is
inconsistent
with
other
environmental
protection
regulations.
(See,
for
example,
Resource
Conservation
and
Recovery
Act
regulations,
40
CFR
parts
264
and
265,
and
Department
of
Transportation
requirements.)
(35,
78,
109,
153)
We
should
require
owners
or
operators
to
retain
records
in
accordance
with
other
205
State
and
Federal
agency
requirements
to
avoid
additional
and
unnecessary
costs.
(114)

2
years.
We
should
reduce
the
record
retention
period
to
two
years.
(45)

Phase­
in.
"API
suggests
that
in
order
to
be
consistent
with
record
retention
requirements
under
the
NPDES
program
of
the
CWA,
records
should
only
be
retained
for
three
years.
However,
if
the
Agency
insists
on
a
new
five
year
requirement,
because
the
required
records
have
only
been
maintained
for
three
years
consistent
with
the
current
regulation,
there
will
be
a
need
for
at
least
a
phase­
in
period
to
bring
those
records
which
were
retained
into
compliance
with
this
new
provision."
(67,
79,
95,
101,
102)

3
years.
Retaining
records
for
three
years
should
be
adequate,
since
we
require
the
review
and
recertification
of
an
SPCC
Plan
every
three
years.
(66)

Small
facilities.

Opposes
requirement.
The
proposed
requirement
to
maintain
records
with
the
SPCC
Plan
for
five
years
would
be
particularly
burdensome
for
small
facilities.
(28,
58,
62,
101)
Proposed
§112.7(
e)
is
only
appropriate
for
large
facilities.
(192)

Favors
requirement.
Maintaining
records
with
the
Plan
should
only
apply
to
small
facilities.
(9,
77)

Response:
Editorial
suggestion.
In
response
to
the
comment
that
we
change
shall
to
must
in
§112.7(
e),
we
agree,
and
have
made
that
change
throughout
the
rule
to
further
our
plain
language
objectives.

Form
of
records.
Records
of
inspections
and
tests
required
by
this
rule
may
be
maintained
in
electronic
or
any
other
format
which
is
readily
accessible
to
the
facility
and
to
EPA
personnel.
Whatever
format
you
use,
however,
must
be
readily
accessible
to
response
personnel
in
an
emergency.
If
such
records
are
produced
in
a
medium
that
is
not
readily
accessible
in
an
emergency,
they
must
also
be
available
in
a
medium
that
is.
For
example,
records
might
be
electronically
produced,
but
computers
fail
and
may
not
be
operable
in
an
emergency.
For
electronic
records,
or
records
produced
in
another
medium,
therefore,
backup
copies
must
be
readily
available
on
paper.
At
least
one
version
of
the
records
should
be
written
in
English
so
that
they
will
be
readily
understood
by
an
EPA
inspector.

Usual
and
customary
business
records
may
be
those
ordinarily
used
in
the
industry,
including
those
made
under
API
standards,
Underwriters'
Laboratories
standards,
NPDES
permits,
a
facility's
Q.
S.­
9000
or
ISO­
14000
system,
or
any
other
format
acceptable
to
the
Regional
Administrator.
If
you
choose
to
use
records
associated
with
compliance
with
industry
standards,
such
as
Underwriters'
Laboratories
standards,
you
206
must
closely
review
the
inspection,
testing,
and
record
keeping
requirements
of
this
rule
to
ensure
that
any
records
kept
in
accordance
with
industry
standards
meets
the
intent
of
the
rule.
Some
standards
have
limited
record
keeping
requirements
and
may
only
address
a
particular
aspect
of
container
fabrication,
installation,
inspection,
and
operation
and
maintenance.
The
intent
of
the
rule
is
that
you
will
not
have
to
maintain
duplicate
sets
of
records
when
one
set
has
already
been
prepared
under
industry
or
regulatory
purposes
that
also
fully
suffices
for
SPCC
purposes.
The
use
of
these
alternative
record
formats
is
optional;
you
are
not
required
to
use
them,
but
you
may
use
them.

We
disagree
that
we
should
omit
written
procedures
for
testing.
Such
procedures
are
essential
for
implementation
of
testing
and
inspection
requirements,
and
must
be
described
in
the
Plan.
We
disagree
that
we
should
include
the
testing
requirements
of
40
CFR
part
280
in
the
rule,
however,
such
procedures
may
be
applicable,
subject
to
good
engineering
practice.

Date.
Dated
records
are
essential
to
document
compliance
with
both
substantive
and
recordkeeping
requirements.
Dated
records
are
also
consistent
with
usual
and
customary
business
practices.

Maintenance
with
Plan.
We
agree
with
commenters
that
it
is
not
necessary
to
maintain
records
as
part
of
the
Plan.
Therefore,
today's
rule
allows
"keeping"
of
the
records
"with"
the
Plan,
but
not
as
part
of
it.
In
the
current
rule,
such
records
"should
be
made
part
of
the
SPCC
Plan...."
40
CFR
112.7(
e)(
8).
Because
you
continually
update
these
records,
this
change
will
eliminate
the
need
to
amend
your
Plan
each
time
you
remove
old
records
and
add
new
ones.
You
still
retain
the
option
of
making
these
records
a
part
of
the
Plan
if
you
choose.

Records
required.
The
rule
permits
use
of
usual
and
customary
business
records,
and
covers
all
of
the
inspections
and
tests
required
by
this
part
as
well
as
any
ancillary
records.
"Inspections
and
tests"
include
not
only
inspections
and
tests,
but
schedules,
evaluations,
examinations,
descriptions,
and
similar
activities
required
by
this
part.

Required
inspections
and
tests.
After
publication
of
this
rule,
we
will
list
all
of
the
inspections
and
tests
required
by
part
112
on
our
website
(www.
epa.
gov/
oilspill).
The
applicability
of
each
inspection
and
test
will
depend
on
the
exercise
of
good
engineering
practice,
because
not
every
one
will
be
applicable
to
every
facility.

Time
period.
We
agree
with
commenters
that
maintenance
of
records
for
three
years
is
sufficient
for
SPCC
purposes,
since
that
period
will
allow
for
meaningful
comparisons
of
inspections
and
tests
taken.
Therefore,
there
will
also
be
no
new
costs.
We
note,
however,
that
certain
industry
standards,
for
example
API
Standards
570
and
653,
may
specify
record
maintenance
for
more
than
three
years.
207
We
disagree
that
we
should
require
record
retention
in
accordance
with
State
and
other
Federal
requirements.
State
and
Federal
record
retention
requirements
vary,
making
it
difficult
to
establish
a
single
standard.

X
­
H:
Training
­
§112.7(
f)

Background:
Section
112.7(
e)(
10)
in
the
current
rule
prescribes
the
employee
training
requirements
and
discharge
prevention
procedures
that
a
facility
owner
or
operator
must
observe.
It
provides
that
owners
or
operators
are
responsible
for
properly
instructing
personnel,
and
scheduling
and
conducting
spill
prevention
briefings
at
intervals
frequent
enough
to
assure
adequate
understanding
of
the
SPCC
Plan.
In
1991,
we
redesignated
§112.7(
e)(
10)
as
§112.7(
f),
and
proposed
to
require:
(1)
an
owner
or
operator
to
conduct
training
exercises
at
least
annually
for
all
personnel,
and
train
new
employees
within
their
first
week
of
work;
and,
(2)
an
owner
or
operator
to
schedule
and
conduct
spill
prevention
briefings
at
least
once
a
year.
We
also
proposed
specific
training
subjects
for
inclusion
in
the
training
program.

Comments:
Support
for
proposal.
"Shell
agrees
with
this
proposal
and
has
been
conducting
such
retaining
at
their
facilities."
(10,
27,
96,
143,
147,
185)

Applicability.

Bulk
storage.
We
should
require
staff
training
for
major
bulk
terminal
and
tank
farm
facilities.
(192)

Existing
programs.
Facilities
should
be
allowed
to
incorporate
SPCC
training
provisions
into
already
existing
training
programs
required
by
other
Federal
or
State
regulations.
(91,
96,
162)

Operation
and
maintenance
of
equipment.
"The
rule
should
only
apply
to
`personnel
involved
in
oil
transfer
operations,
emergency
response,
and
countermeasure
activities."
It
should
not
apply
to
clerks,
secretaries,
and
like
employees.
(14,
35,
42,
45,
48,
57,
62,
66,
67,
71,
77,
88,
92,
98,
103,
115,
117,
125,
141,
164,
167,
173,
175,
180,
181,
182,
187,
189,
L7,
L12,
L18,
L24)

Small
facilities.
We
should
provide
for
a
small
facility
exemption.
(79,
109,
175,
180,
182)

Content
of
training.
Training
should
address
the
initial
response
to
a
spill,
such
as
emergency
notification
and
implementation
of
emergency
containment
measures.
Exercises
of
these
emergency
plans
should
be
conducted
at
least
annually.
(1)
Objects
to
the
proposal
that
employees
be
trained
in
maintenance
of
oil
storage
equipment
or
oil
transfer
procedures.
(42,
125)

Discharge
prevention
briefings.
"API
suggests
that
section
112.7(
f)(
3)
be
amended
to
require
`briefings
for
operating
personnel
at
least
once
a
year
...
to
assure
understanding
208
of
the
SPCC
plan
for
that
facility
in
conjunction
with
the
annual
training.
'
This
paragraph
should
also
require
briefings
of
`new
operational
employees
during
their
indoctrination
with
their
job
responsibilities,
and
as
appropriate
for
all
affected
operational
personnel
when
changes
are
made
to
the
existing
Plan
necessitating
recertification."
(67)
Favors
the
present
requirement
to
hold
spill
prevention
briefings
"at
intervals
frequent
enough
to
assure
adequate
understanding
of
the
SPCC
Plan."
(78)

Documentation.
The
rule
should
include
a
provision
that
owners
or
operators
document
each
training
session
and
spill
response
drill
conducted,
and
maintain
training
session
and
drill
records
for
five
years.
(47,
96)

Editorial
suggestion.
We
should
clarify
proposed
§112.7(
f),
in
which
we
continue
to
use
the
word
should.
The
commenter
suggested
that
we
replace
should
with
either
shall
or
"it
is
recommended"
to
avoid
confusion.
(16)

Timing
of
employee
training.

Support
for
annual
training
requirement.
We
should
allow
owners
or
operators
to
coordinate
SPCC
Plan
training
with
local
oil
spill
response
organizations
or
Local
Emergency
Planning
Committees
(LEPCs)
whenever
possible.
(27)
Favors
proposed
provision
for
annual
training
exercises.
(27,
34,
141)

Opposition
to
prescribed
training
periods.
We
should
avoid
requiring
a
period
for
conducting
training
exercises.
(62,
66,
71,
109,
113,
128)

Drills.
The
annual
training
should
not
be
considered
a
full­
scale
SPCC
drill.
(L3)

New
employees.
We
should
define
the
phrase
new
employee.
(103)
Others
oppose
the
provision
to
train
new
employees
within
one
week
of
employment,
arguing
that
such
a
provision
is
impractical,
and
called
for
employer
discretion
in
scheduling
training.
Some
suggested
varying
time
periods
in
lieu
of
one
week.
Those
suggestions
ranged
from
one
month
to
one
year,
with
alternatives
suggested
such
as
"as
soon
as
practical,"
"prior
to
operation
but
before
one
year,"
"within
one
week
of
job
assignment,"
"a
more
reasonable
time
period,"
"after
training,"
and
"until
the
next
annual
training
for
all
employees."
(5,
28,
31,
34,
35,
36,
38,
55,
57,
62,
66,
67,
70,
71,
77,
79,
87,
89,
90,
92,
93,
96,
98,
101,
103,
113,
114,
115,
117,
118,
125,
128,
133,
141,
145,
155,
158,
162,
164,
173,
182,
187,
189,
L6,
L7,
L14,
L29)

Response:
Support
for
proposal.
We
appreciate
commenter
support.

Applicability.
We
believe
that
training
requirements
should
apply
to
all
facilities,
large
or
small,
including
all
those
that
store
or
use
oil,
regardless
of
the
amount
of
oil
transferred
in
any
particular
time.
Training
may
help
avert
human
error,
which
is
a
principal
cause
of
oil
discharges.
"Spills
from
ASTs
may
occur
as
a
result
of
operator
error,
for
example,
during
loading
operations
(e.
g.,
vessel
or
tank
truck
­
AST
transfer
operation),
209
or
as
a
result
of
structural
failure
(e.
g.,
brittle
fracture)
because
of
inadequate
maintenance
of
the
AST."
EPA
Liner
Study
at
14.
The
1995
SPCC
Survey
found
that
operator
error
was
the
most
common
spill
cause
for
facilities
in
9
of
the
19
industry
categories
that
reported
having
spills.
Also,
the
August
1994
draft
report
of
the
Aboveground
Oil
Storage
Facilities
Workgroup
called
"Soil
and
Ground
Water
Contamination
from
Aboveground
Oil
Storage
Facilities:
A
Strategic
Study"
presented
data
on
causes
of
discharges
from
two
studies.
Both
studies
showed
that
error
during
product
transfer
activities
is
one
of
the
biggest
known
causes
of
discharges
at
AST
facilities.
Two
other
studies
also
support
our
contention:
Carter,
W.
J.,
"How
API
Viewed
the
Needs
for
Aboveground
Storage
Tanks,"
Tank
Talk,
Vol.
7,
July/
August
1992,
p.
2.;
and
U.
S.
EPA,
"The
Technical
Background
Document
to
Support
the
Implementation
of
OPA
Response
Plan
Requirements,"
Emergency
Response
Division,
Office
of
Solid
Waste
and
Emergency
Response,
February
1993,
p.
4­
19.
We
have
therefore
retained
the
applicability
of
training
to
all
facilities.
The
1993
proposal
would
have
limited
training
requirements
to
only
certain
facilities
which
received
or
transferred
over
the
proposed
amount
of
oil.
Facilities
which
receive
or
transfer
less
than
the
proposed
amount
might
also
have
discharges
which
could
have
been
averted
through
required
training.
Also
the
proposed
rule
would
have
exempted
many
facilities
that
use
rather
than
store
oil
from
its
scope.
Therefore,
we
have
provided
in
the
rule
that
all
facilities,
whether
bulk
storage
facilities
or
facilities
that
merely
use
oil,
must
train
oilhandling
employees
because
all
facilities
have
the
potential
for
a
discharge
as
described
in
§112.1(
b),
and
training
is
necessary
to
avert
such
a
discharge.

We
agree
with
the
commenter
that
training
is
only
necessary
for
personnel
who
will
use
it
to
carry
out
the
requirements
of
this
rule.
Therefore
revised
paragraph
(f)(
1)
provides
that
only
oil­
handling
personnel
are
subject
to
training
requirements,
as
we
proposed
in
1993.
"Oil­
handling
personnel"
is
to
be
interpreted
according
to
industry
standards,
but
includes
employees
engaged
in
the
operation
and
maintenance
of
oil
storage
containers
or
the
operation
of
equipment
related
to
storage
containers
and
emergency
response
personnel.
We
do
not
interpret
the
term
to
include
secretaries,
clerks,
and
other
personnel
who
are
never
involved
in
operation
or
maintenance
activities
related
to
oil
storage
or
equipment,
oil
transfer
operations,
emergency
response,
countermeasure
functions,
or
similar
activities.

Existing
programs.
You
may
incorporate
SPCC
training
requirements
into
already
existing
training
programs
required
by
other
Federal
or
State
law
at
your
option
or
may
conduct
SPCC
training
separately.
You
may
coordinate
such
training
with
training
on
other
subjects,
or
with
other
agencies
like
LEPCs
or
oil
spill
response
organizations.

Content
of
training.
Specifying
a
minimum
list
of
training
subjects
is
necessary
to
ensure
that
facility
employees
are
aware
of
discharge
prevention
procedures
and
regulations.
As
suggested
by
a
commenter,
we
have
added
knowledge
of
discharge
procedure
protocols
to
the
list
of
training
subjects
because
such
training
will
help
avert
discharges.
Therefore,
we
have
specified
that
training
must
include,
at
a
minimum:
the
operation
and
maintenance
of
equipment
to
prevent
the
discharge
of
oil;
discharge
210
procedure
protocols;
applicable
pollution
control
laws,
rules,
and
regulations;
general
facility
operations;
and,
the
contents
of
the
facility
Plan.
As
noted
above,
we
require
response
training
for
facilities
that
must
submit
response
plans,
but
such
training
is
not
necessary
for
all
SPCC
facilities.

In
response
to
the
utility
commenter
who
asserted
that
utility
employees
do
not
need
to
be
trained
in
the
maintenance
of
oil
storage
tanks
because
such
maintenance
does
not
involve
the
transfer
and
handling
of
oil,
we
note
that
training
must
address
relevant
maintenance
activities
at
the
facility.
If
there
is
no
transfer
and
handling
of
oil,
such
topic
need
not
be
covered
in
training.

Discharge
prevention
briefings.
Annual
discharge
prevention
briefings
are
necessary,
but
there
should
be
more
frequent
briefings
where
appropriate.
Such
briefings
are
necessary
to
refresh
employees'
memories
on
facility
Plan
provisions
and
to
update
employees
on
the
latest
prevention
and
response
techniques.
Training
must
include
the
contents
of
the
facility
Plan.
Although
it
is
desirable,
we
disagree
that
we
should
require
SPCC
briefings
to
include
emergency
response
training.
That
training
is
already
required
for
those
facilities
which
must
prepare
response
plans.

Documentation.
You
must
document
that
you
have
conducted
required
training
courses.
Such
documentation
must
be
maintained
with
the
Plan
for
three
years.

Editorial
suggestion.
We
agree
with
the
commenter,
and
have
made
the
editorial
change
from
"should"
to
"must"
for
all
requirements.
We
have
eliminated
all
recommendations
from
the
rule
to
avoid
confusing
the
regulated
public
with
what
is
mandatory
and
what
is
discretionary.
Therefore,
no
shoulds
remain
in
the
rule.

Timing
of
employee
training.
We
agree
with
commenters
who
thought
it
desirable
to
leave
the
timing
and
number
of
hours
of
training
of
oil­
handling
employees,
including
new
employees,
to
the
employer's
discretion.
"Proper
instruction"
of
oil­
handling
employees,
as
required
in
the
rule,
means
in
accordance
with
industry
standards
or
at
a
frequency
sufficient
to
prevent
a
discharge
as
described
in
§112.1(
b).
This
standard
will
allow
facilities
more
flexibility
to
develop
training
programs
better
suited
to
the
particular
facility.
While
the
rule
requires
annual
discharge
prevention
briefings,
we
also
agree
that
the
annual
briefings
required
are
not
drills.
In
any
case,
the
SPCC
rules
do
not
require
drills,
as
explained
below.

For
purposes
of
the
rule,
it
is
not
necessary
to
define
a
"new
employee"
because
all
oilhandling
personnel
are
subject
to
training
requirements,
whether
new
or
not.
You
do,
however,
have
discretion
as
to
the
timing
of
that
training,
so
long
as
the
timing
meets
the
requirements
of
good
engineering
practice.

Unannounced
drills.
The
proposed
yearly
frequency
for
unannounced
drills
is
also
unnecessary
because
such
drills
are
already
required
at
FRP
facilities,
which
are
higher
risk
facilities.
We
do
not
believe
that
the
risk
at
all
SPCC
211
facilities
approaches
the
same
level
as
at
FRP
facilities.
Therefore,
we
are
not
finalizing
this
proposal,
and
there
are
no
new
costs.

X
­
I:
Security
(excluding
oil
production
facilities)
­
§112.7(
g)

Background:
Since
vandalism
is
a
factor
in
many
spills,
we
proposed
in
1991,
to
modify
the
provisions
for
adequate
and
effective
security.
We
also
proposed
to
redesignate
§112.7(
e)(
9)
as
§112.7(
g).
These
provisions
would
prevent
facility
access
by
unauthorized
persons
and
prevent
tampering
with
equipment
and
tanks.
We
proposed
in
§112.7(
g)(
1)
to
recommend
­
not
require
­
that
owners
or
operators
fully
fence
all
plants
handling,
processing,
or
storing
oil,
and
ensure
that
gates
are
locked
or
guarded
when
the
facility
is
not
in
production
or
is
unattended.

In
§112.7(
g)(
2),
we
proposed
to
clarify
that
under
current
§112.7(
e)(
9)(
ii),
an
owner
or
operator
must
have
adequate
security
to
ensure
that
valves
remain
in
the
closed
position
when
in
non­
operating
or
non­
standby
status.
These
valves
include
master
flow
and
drain
valves
and
any
other
valves
that
permit
direct
outward
flow
of
the
tank's
contents
to
the
surface.
This
proposal
would
allow
owners
or
operators
more
flexibility
in
choosing
a
method
of
securing
the
valves,
because
the
current
rule
requires
the
valves
to
be
locked.

We
proposed
editorial
changes
in
redesignated
§112.7(
g)(
3)
(currently
§112.7(
e)(
9)(
iii))
to
require
that
an
owner
or
operator
lock
the
starter
control
on
all
pumps
in
the
"off"
position.
When
the
pumps
are
in
a
non­
operating
or
non­
standby
status,
the
owner
or
operator
would
have
to
locate
the
starter
control
at
a
site
accessible
only
to
authorized
personnel.

Proposed
§112.7(
g)(
4)
(currently
§112.7(
e)(
9)(
iv))
would
require
an
owner
or
operator
to
ensure
that
oil
pipeline
loading
and
unloading
connections
are
securely
capped
or
blank­
flanged
when
not
in
service
or
standby
service
for
an
extended
time.
We
proposed
to
clarify
that
"an
extended
time"
is
six
months
or
more.

We
proposed
to
recommend
in
redesignated
§112.7(
g)(
5)
(currently
§112.7(
e)(
9)(
v))
that
facility
lighting
be
commensurate
with
the
facility
type
and
location.

Comments:
Support
for
proposal.
Favors
recommendations
for
establishing
security
at
a
facility.
(143)

Opposition
to
proposal.
We
should
tailor
security
requirements
to
specific
facility
needs.
The
PE
and
any
responsible
company
official
should
determine
the
security
requirements.
(162)

Applicability.

Mobile
facilities.
"Mobile
facilities
should
be
exempt
from
the
requirements
as
well.
When
in
operation
they
are
manned
24
hours
per
day.
In
addition,
the
212
physical
requirements
such
as
landing,
loading
and
unloading
connections
are
not
applicable
to
a
mobile
facility."
(128)

Editorial
suggestion.
We
should
define
the
term
"plant."
Security
options
often
are
limited
for
facilities
located
in
residential
areas.
(37)

Fences.

Recommendation.
We
should
recommend
that
owners
or
operators
fully
fence
plants
with
a
chain
link
fence
with
barbed
wire
­
an
adequate
system
for
deterring
vandalism.
(16)
Supports
§112.7(
g)(
1)
recommendation
to
fence
a
facility,
since
owners
or
operators
need
discretion
not
to
fence
where
it
is
impracticable
or
undesirable.
(57)

Requirement.
We
should
change
the
proposed
§112.7(
g)(
1)
recommendation
to
a
requirement
or
delete
it.
(121)

Loading/
unloading
connections.
"Larger
facilities
often
have
seasonal
or
contractual
variations
in
the
use
of
lines,
pumps,
racks
and
connections.
Therefore,
it
would
be
costly
and
impractical
to
blank
off
lines
only
to
reopen
them
in
the
seventh
month.
At
such
facilities,
an
unused
tank
would
be
closed
but
the
piping
would
remain
open.
Accordingly,
the
regulation
should
recognize
normal
operating
procedures
at
some
facilities
and
provide
operating
flexibility
while
maintaining
the
necessary
security."
(54)
We
should
specify
that
"securely
capped"
connections
include
quick­
disconnect
fittings.
(92)
We
should
clarify
that
the
second
sentence
in
§112.7(
g)(
4)
regarding
the
loading
and
unloading
connection
provision
included
piping
emptied
of
liquid
content
either
by
draining
or
by
inert
gas
pressure.
(121)
Supports
proposal
that
"an
extended
time"
means
more
than
six
months.
(147)

Starter
controls
on
pumps.
"IFTOA
recommends
that
EPA
modify
the
requirement
so
that
it
would
apply
to
facilities,
not
pumps,
that
have
been
closed
for
six
months
or
more
and
the
rule
should
be
amended
to
read
`locked
in
the
`off'
position
or
electronically
disconnected.
'
Disconnection,
of
course,
serves
the
same
purpose
and
frequently
is
much
easier
to
control."
(54)
"There
is
no
need
for
the
double
security
being
proposed
with
the
word
`and'
instead
of
`or'
in
the
aforementioned
requirement.
Such
double
security
offers
no
additional
benefit
to
deter
vandals
or
other
unauthorized
persons."
(67,
79,
85,
95,
102)
"At
a
large
facility,
such
a
security
requirement
becomes
unwieldy.
The
potential
for
losing
keys
or
having
the
locks
become
inoperative
due
to
freezing
conditions
is
great."
(88)
We
should
state
that
pumps
must
be
locked
in
the"
off"
position.
(121)

Response:
Support
for
proposal.
We
appreciate
commenter
support.

Applicability
of
requirements.
We
asked
in
the
1991
preamble
(at
56
FR
54616)
for
comments
as
to
whether
provisions
proposed
as
discretionary
measures
or
recommendations
should
be
made
requirements.
We
were
concerned
whether
these
213
proposed
measures
represented
good
engineering
practice
for
all
facilities.
Specific
comments
are
discussed
below.
In
the
case
of
proposed
§112.7(
g)(
1)
and
(5)
as
requirements,
we
have
decided
to
retain
the
requirements
as
requirements
rather
than
convert
those
paragraphs
into
recommendations
as
proposed.
We
have
done
this
because
we
believe
that
fencing,
facility
lighting,
and
the
other
measures
prescribed
in
the
rule
to
prevent
vandalism
are
elements
of
good
engineering
practice
in
most
facilities,
including
mobile
facilities.
Where
they
are
not
a
part
of
good
engineering
practice,
we
have
amended
the
proposed
provision
allowing
deviations,
§112.7(
a)(
2),
to
include
the
provisions
in
§112.7(
g).

Editorial
suggestion.
We
agree
that
the
term
"plant"
has
no
clear
meaning.
Therefore,
in
paragraph
(g)(
1),
we
have
substituted
the
term
"facility"
in
its
place,
which
is
a
defined
term
in
these
rules.

Fences.
Fencing
helps
to
deter
vandals
and
thus
prevent
the
discharges
that
they
might
cause.
In
response
to
the
commenter
who
argued
that
fences
should
be
topped
with
barbed
wire,
or
otherwise
designed
to
deter
vandalism,
we
agree.
When
you
use
a
fence
to
protect
a
facility,
the
design
of
the
fence
should
deter
vandalism.
Methods
of
deterring
vandals
might
include
barbed
wire
or
other
devices.
If
any
type
of
fence
is
impractical,
you
may,
under
§112.7(
a)(
2),
explain
your
reasons
for
nonconformance
and
provide
equivalent
environmental
protection
by
some
other
means.

Loading/
unloading
connections.
In
response
to
comment,
we
have
decided
to
retain
the
current
time
line
in
§112.7(
g)(
4),
i.
e.,
"an
extended
time,"
instead
of
specifying
a
sixmonth
time
line,
due
to
the
need
for
operational
flexibility
at
facilities.
We
define
"an
extended
time"
in
reference
to
industry
standards
or,
in
the
absence
of
such
standards,
at
a
frequency
sufficient
to
prevent
any
discharge.
The
appropriate
method
of
securing
or
blank
flanging
of
these
connections
is
a
matter
of
good
engineering
practice,
and
might
include
"quick
disconnect
fittings"
as
a
possible
deviation
under
§112.7(
a)(
2).
In
any
case,
a
secure
cap
is
one
equipped
with
some
kind
of
lock
or
secure
closure
device
to
prevent
vandalism.
We
disagree
that
the
requirements
of
this
paragraph
should
apply
to
the
owner
or
operator
of
a
facility
instead
of
the
owner
or
operator
of
the
piping
because
a
facility
might
place
only
some
piping
out
of
service
for
a
period
of
time,
and
let
other
piping
remain
in
service.
Therefore,
the
owners
or
operators
of
some
piping
might
escape
the
requirements
of
the
rule
and
be
more
likely
to
discharge
oil.

We
disagree
that
this
requirement
is
costly
or
impractical.
The
requirement
may
save
money
by
preventing
costly
discharges
and
cleanups.

Regarding
making
the
§112.7(
g)(
4)
requirements
apply
to
facilities
(not
piping),
we
decline
to
make
this
change
because
facilities
in
service
often
place
some,
but
not
all,
of
the
piping
out­
of­
service
for
some
period.
The
current
requirement
covers
any
piping
out­
of­
service
for
an
extended
time,
regardless
of
whether
the
facility
is
in
service.

In
response
to
comment,
we
note
that
paragraph
(g)(
4)
applies
to
piping
emptied
of
liquid
content
either
by
draining
or
by
inert
gas
pressure.
214
Starter
controls
on
pumps.
We
disagree
that
the
requirements
to
have
the
starter
control
locked
in
the
off
position
and
be
accessible
only
to
authorized
personnel
are
redundant.
Restricting
access
to
such
pumps
prevents
unauthorized
personnel
from
accidentally
opening
the
starter
control.
These
measures
are
necessary
to
prevent
discharges
at
small
as
well
as
large
facilities
because
the
threat
of
discharge
is
the
same
regardless
of
the
size
of
the
container,
and
a
small
discharge
may
be
harmful
to
the
environment.
If
the
potential
for
losing
keys,
weather
conditions
such
as
frequent
freezing,
or
other
engineering
factors
render
such
a
measure
infeasible,
you
may
use
the
deviation
provisions
in
§112.7(
a)(
2)
if
you
can
explain
your
reasons
for
nonconformance
and
provide
equivalent
environmental
protection
by
some
other
means.

A
facility
may
have
some,
but
not
all,
pumps
out­
of­
service
for
various
periods
­
even
during
facility
operations.
We
decline
to
exempt
pumps
which
are
out­
of­
service
for
six
months
or
more
because
it
would
reduce
the
effectiveness
of
this
preventive
measure
by
leaving
some
piping
unprotected
for
up
to
half
a
year.

Valves.
Revised
§112.7(
g)(
2)
requires
you
to
ensure
that
the
master
flow
and
drain
valves
and
other
valves
permitting
outward
flow
of
the
container's
contents
have
adequate
security
measures.
The
current
rule
requires
that
such
valves
be
securely
locked
in
the
closed
position
when
in
non­
operating
or
non­
standby
status.
Today's
revised
rule
allows
security
measures
other
than
locking
drain
valves
or
other
valves
permitting
outflow
to
the
surface.
Manual
locks
may
be
preferable
for
valves
that
are
not
electronically
or
automatically
controlled.
Such
locks
may
be
the
only
practical
way
to
ensure
that
valves
stay
in
the
closed
position.
For
electronically
controlled
or
automated
systems,
no
manual
lock
may
be
necessary.
The
rule
gives
you
discretion
in
the
method
of
securing
valves.
We
believe
that
this
flexibility
is
necessary
due
to
changes
in
technology
and
in
the
use
of
manual
and
electronic
valving.

X
­
J:
Facility
tank
car
and
tank
truck
loading/
unloading
racks
­
§112.7(
h)

Background:
Section
112.7(
e)(
4)
of
the
current
rule
describes
the
precautionary
measures
an
owner
or
operator
must
undertake
in
tank
car
and
tank
truck
loading/
unloading
racks
to
prevent
discharges
during
transfers.
Section
§112.7(
e)(
4)(
i)
requires
that
tank
car
and
tank
truck
loading
and
unloading
procedures
meet
the
Department
of
Transportation's
(DOT)
minimum
requirements
and
regulations.
Section
112.7(
e)(
4)(
ii)
requires
that,
where
rack
area
drainage
does
not
flow
into
a
catchment
basin
or
treatment
facility
designed
to
handle
spills,
an
owner
or
operator
must
use
a
quick
drainage
system.
Further,
the
containment
system
must
be
able
to
hold
at
least
the
maximum
capacity
of
any
single
compartment
of
a
tank
car
or
tank
truck
loaded
or
unloaded
at
the
plant.
Under
§112.7(
e)(
4)(
iii),
an
owner
or
operator
must
use
an
interlocked
warning
light,
physical
barrier
system,
or
warning
signs
in
loading/
unloading
areas
to
prevent
vehicular
departure
before
complete
disconnect.
Section
112.7(
e)(
4)(
iv)
of
the
current
rule
describes
the
examination
and
maintenance
requirements
that
must
be
completed
prior
to
filling
and
departure.
215
In
1991,
we
reproposed
current
§112.7(
e)(
4),
with
a
few
changes.
In
§112.7(
h)(
1),
we
proposed
language
requiring
that
tank
truck
loading/
unloading
procedures
meet
the
minimum
requirements
and
regulations
established
by
State
and
Federal
law,
in
place
of
the
current
requirement
that
these
procedures
comply
with
DOT
requirements
and
regulations.

Comments:
Alarm
or
warning
systems.
EPA
should
consider
"adding
the
additional
requirement
that
wheel
chocks
be
used
during
all
tank
truck
transfers
"to
guarantee
that
tank
trucks
will
not
roll
unexpectedly
while
the
loading
arm
is
attached
and
the
driver
is
out
of
the
cab."
(16)
We
should
revise
§112.7(
h)(
3)
to
include
additional
industry
standard
equipment,
and
read
as
follows:
"(
3)
An
interlocked
warning
light
or
physical
barrier
system,
vehicle
brake
interlock
system,
or
warning
signs,
or
a
system
substantially
similar
in
effectiveness
shall
be
provided
.
.
."
(83)

Applicability.
Asks
us
to
clarify
which
types
of
facilities
are
subject
to
these
provisions.
(79)
Asks
whether
this
section
applies
only
to
facilities
"routinely
used
for
loading
or
unloading
of
tanker
trucks
from
or
into
aboveground
bulk
storage
tanks"
or
to
any
loading
or
unloading
operation.
(125)

Phase­
in.
We
should
allow
facility
owners
or
operators
at
least
two
years
to
comply
with
the
requirements
of
this
section.
(71)
We
should
provide
more
than
60
days
from
the
date
we
promulgate
the
final
rule.
(125)

Production
facilities.
"We
believe
that
EPA
should
clarify
that
the
provisions
of
this
section
do
not
apply
to
crude
oil
transfers
from
production
fields
into
tank
trucks.
Adequate
protection
from
the
small
drips
that
may
occur
from
transferring
crude
to
a
tank
truck
is
provided
by
a
small
sump
or
catchment
basin."
(75,
145,
167)

Small
facilities.
We
should
exempt
small
oil
production
facilities.
(28,
79,
175)
We
should
exempt
small
aboveground
tanks
containing
1,000
barrels
or
less
of
oil.
A
portable
drip
plan
has
been
sufficient
for
the
degree
of
spill
risk
at
such
facilities.
(67,
91,
101)
Onshore
production
facilities
should
be
exempted
because
they
are
small
and
have
a
negligible
spill
history.
(167)

Warning
system.
Asks
whether
the
interlocking
warning
system
requirement
applies
to
tank
batteries,
plants,
or
both.
(28,
101)

Cost.
Most
Appalachian
oil
production
operations
would
have
to
newly
install
the
secondary
containment
system
required
under
this
section.
Asks
whether
we
factored
the
economic
impact
of
installing
such
containment
into
the
fiscal
impact
of
the
proposed
rule.
(28,
31,
113,
165,
187,
L15)

Editorial
suggestions.
We
should
replace
loading/
unloading
rack
with
loading/
unloading
area
in
the
section
title
to
clarify
that
the
provisions
apply
to
all
types
of
loading/
unloading
stations.
(47)
We
should
define
facility
tank
car
and
tank
truck
216
loading/
unloading
racks
to
clarify
the
type
of
facility
to
which
this
provision
applies.
(58,
79)
We
should
move
all
of
§112.7(
h)
to
§112.8.
(121)

Other
State
or
Federal
law.
"While
SPCC
facilities
are
subject
to
such
requirements
in
addition
to
the
SPCC
rules,
failure
to
meet
such
other
requirements
should
not
constitute
a
violation
of
the
SPCC
rules."
(67)
We
should
remove
the
reference
to
other
state
and
federal
law
from
the
rule.
(121)
"The
Company
feels
that
proposed
§112.7(
h)
should
be
eliminated.
...
These
are
Department
of
Transportation
items
and
should
be
covered
by
that
Department's
rules
governing
loading,
unloading,
and
vehicle
inspection.
The
compliance
onus
should
be
on
the
transporter."
(164)

Secondary
containment.

Support.
Some
degree
of
secondary
containment
is
necessary
during
truck
loading,
but
questions
the
need
for
such
a
large
catchment
system.
(187)

Contingency
plan
instead.
We
should
allow
a
strong
contingency
plan
in
place
of
secondary
containment.
(28,
31,
101,
165,
L15)

Methods.
We
should
clarify
whether
the
use
of
any
of
the
discharge
prevention
systems
in
§112.7(
c)
would
satisfy
§112.7(
h)(
1)
that
the
containment
system
be
designed
"to
hold
at
least
the
maximum
capacity
of
any
single
compartment
of
a
tank
car
or
tank
truck
loaded
or
unloaded
in
the
plant."
(115)

Quick
drainage
system.
We
should
define
the
term
quick
drainage
system.
Asks
whether
there
are
other
acceptable
ways
to
comply
with
this
regulation
(e.
g.,
blocking
nearby
storm
drains).
(29)
Recommends
that
we
allow
owners
or
operators
to
use
the
drainage
control
structures/
equipment
listed
in
§112.7(
c)
in
place
of
the
quick
drainage
system.
(124)

Completely
buried
tanks.
"The
Ohio
Utilities
request
U.
S.
EPA
interpretation
on
whether
such
requirement
applies
solely
to
aboveground
tank
loading
and
unloading
areas,
or
whether
it
would
also
apply
to
underground
storage
tank
loading
and
unloading
areas
as
well.
If
this
provision
attempts
to
regulate
underground
storage
tanks
loading
and
unloading
areas,
the
Ohio
Utilities
strongly
believe
that
such
attempted
regulation
is
inappropriate
and
would
result
in
a
multiplicity
of
regulation
since
the
federal
underground
storage
tank
regulations,
40
CFR
part
280,
already
regulate,
to
some
extent,
the
loading
and
unloading
procedures
of
underground
storage
tanks."
(189)

Response
personnel
instead.
"Because
many
tank
car
loading/
unloading
facilities
are
located
on
railroad
property,
or
modifications
that
could
undermine
the
railway
bed
are
subject
to
railroad
approval,
providing
containment
for
railcars
is
typically
not
feasible.
...
Operators
should
have
the
option
of
providing
for
response
personnel
to
be
placed
on
alert
when
such
an
activity
is
to
take
place,
and,
where
site
conditions
allow,
provide
a
capture
plan
similar
to,
but
more
217
limited
in
scope,
than
a
full
contingency
plan.
This
would
encourage
secondary
containment
for
storage
tanks
and
other
potential
sources."
(76)

Unnecessary,
procedures
instead.
"GM
believes
that
mandatory
tank
car
loading
and
unloading
containment
systems
designed
to
hold
at
least
the
maximum
capacity
of
any
single
compartment
of
a
tank
car
or
tank
truck
is
unnecessary
and
costly.
The
cost
to
renovate
existing
loading
and
unloading
areas
at
large
manufacturing
facilities
is
substantial
and
may
have
negligible
environmental
benefit
if
a
spill
does
not
occur
or
if
the
spill
is
not
the
entire
contents
of
the
tanker.
...
GM
recommends
that
in
lieu
of
mandatory
containment
of
the
entire
contents
of
the
largest
compartment
of
the
tanker,
an
owner
be
allowed
to
demonstrate
that
procedures
are
in
place
to
ensure
that
personnel
are
present
at
all
times
to
supervise
tank
truck
loading
and
unloading."
(90)

Vehicle
drain
closure.
"Accordingly,
EPA
should
delete
that
portion
of
proposed
section
112.7(
h)(
4)
relating
to
examination
and
repair
of
trucks
from
the
final
rule.
First,
in
most
cases
the
trucks
that
pull
up
under
a
terminal's
rack
do
not
belong
to
the
owner
or
operator
of
the
facility.
They
are
the
property
of
petroleum
marketers
who
are
independent
from
the
facility
owner
or
operator.
...
Second,
facility
employees
are
not
trained
or
capable
of
properly
examining
and
repairing
trucks
to
prevent
leakage,
and
such
an
obligation
certainly
could
result
in
a
major
safety
problem.
Third,
many
facilities
are
completely
automated
or
automated
during
certain
periods
of
time
during
the
day
or
night;
there
is
no
one
at
the
facility.
Thus,
the
requirement
would
prevent
the
operation
of
terminals
at
these
times
and
would
substantially
disrupt
the
petroleum
distribution
system
nationwide.
Fourth,
the
Department
of
Transportation
imposes
the
responsibility
for
maintenance
and
repair
of
motor
vehicles
on
the
owner
or
operator
of
the
vehicle,
the
individual
who
controls
the
vehicle.
EPA
should
adopt
the
same
policy."
(54,
115)

Response:
Alarm
or
warning
systems.
The
requirement
to
provide
a
warning
light
or
other
physical
barrier
system
applies
to
the
loading/
unloading
areas
of
facilities.
We
have
amended
the
rule
on
the
suggestion
of
a
commenter
to
include
"vehicle
brake
interlock
system
or
other
system
substantially
similar
in
effectiveness,"
and
"wheel
chocks."
The
examples
listed
in
the
rule
of
potential
warning
systems
are
merely
illustrative.
Any
other
alarm
or
warning
system
which
serves
the
same
purpose
and
performs
effectively
will
also
suffice
to
meet
this
requirement.

Applicability.
This
section
is
applicable
to
any
non­
transportation­
related
or
terminal
facility
where
oil
is
loaded
or
unloaded
from
or
to
a
tank
car
or
tank
truck.
It
applies
to
containers
which
are
aboveground
(including
partially
buried
tanks,
bunkered
tanks,
or
vaulted
tanks)
or
completely
buried
(except
those
exempted
by
this
rule),
and
to
all
facilities,
large
or
small.
All
of
these
facilities
have
a
risk
of
discharge
from
transfers.
Our
Survey
of
Oil
Storage
Facilities
(published
in
July
1996)
showed
that
as
annual
throughput
increases,
so
does
the
propensity
to
discharge,
the
severity
of
the
discharge,
and,
to
a
lesser
extent,
the
costs
of
the
cleanup.
Throughput
increases
are
often
associated
with
transfers
of
oil.
218
The
requirements
contained
in
this
section,
including
those
for
secondary
containment,
warning
systems,
and
inspection
of
trucks
or
cars
for
discharges
are
necessary
to
help
prevent
discharges.
If
you
can
justify
a
deviation
for
secondary
containment
requirement
in
paragraph
(h)(
1)
on
the
basis
that
it
is
not
practicable
from
an
engineering
standpoint,
you
must
provide
a
contingency
plan
and
take
other
actions
to
comply
with
§112.7(
d).
If
you
seek
to
deviate
from
any
of
the
requirements
in
paragraphs
(h)(
2)
or
(3),
you
must
explain
your
reasons
for
nonconformance,
as
provided
in
§112.7(
a)(
2),
and
provide
measures
affording
equivalent
environmental
protection.

We
disagree
that
a
contingency
plan
(whether
labeled
"strong"
or
otherwise)
is
a
preferable
alternative
to
secondary
containment.
Secondary
containment
is
preferable
because
it
may
prevent
a
discharge
that
may
be
harmful
as
described
in
§112.1(
b).
A
contingency
plan
is
a
plan
for
action
when
such
discharge
has
already
occurred.
However,
as
noted
earlier,
if
secondary
containment
is
not
practicable,
you
must
provide
a
contingency
plan
and
take
other
actions
as
required
by
§112.7(
d).
EPA
will
continue
to
evaluate
the
issue
of
whether
the
provisions
for
secondary
containment
found
in
§112.7(
h)(
1)
should
be
modified
or
revised.
We
intend
to
publish
a
notice
asking
for
additional
data
and
comment
on
this
issue.

We
disagree
that
the
section
regulates
activities
already
under
the
purview
of
the
U.
S.
Department
of
Transportation.
We
regulate
the
environmental
aspects
of
loading/
unloading
transfers
at
non­
transportation­
related
facilities,
which
are
legitimately
part
of
a
prevention
plan.
DOT
regulates
other
aspects
of
those
transfers,
such
as
safety
measures.

Phase­
in.
None
of
the
requirements
of
§112.7(
h)
are
new,
therefore
compliance
is
already
required,
and
no
phase­
in
is
necessary.

Cost.
We
believe
that
we
have
considered
costs
adequately,
and
invite
the
interested
reader
to
review
the
Regulatory
Analyses
in
the
docket
for
this
rulemaking.
This
is
not
a
new
requirement,
and
therefore,
none
of
the
costs
are
"new".
Appalachian
and
other
oil
production
operators
who
are
presently
in
compliance
with
these
provisions
will
not
incur
additional
economic
impact
as
a
result
of
the
revision.

Editorial
suggestion.
We
disagree
that
we
should
change
loading
rack
to
"loading/
unloading
area"
because
we
did
not
propose
the
change.
We
disagree
that
we
should
move
the
requirements
to
§112.8.
We
intend
§112.7(
h)
to
apply
to
all
facilities,
including
production
facilities;
§112.
8
does
not
cover
production
facilities.

Other
State
or
Federal
law.
We
have
withdrawn,
as
unnecessary,
proposed
§112.7(
h)(
1),
which
would
have
required
that
facilities
meet
the
minimum
requirements
of
Federal
and
State
law.
Those
requirements
apply
whether
they
are
mentioned
or
not.

Secondary
containment.
As
noted
above,
the
requirement
for
secondary
containment
applies
to
all
facilities,
whether
with
aboveground
or
completely
buried
containers.
This
219
includes
production
facilities
and
small
facilities.
The
method
of
secondary
containment
must
be
one
of
those
listed
in
the
rule
(see
§112.7(
c)),
or
some
similar
system
that
provides
equivalent
environmental
protection.
The
choice
of
method
is
one
of
good
engineering
practice.
However,
in
response
to
comments,
we
note
that
sumps
and
drip
pans
are
a
listed
method
of
secondary
containment
for
offshore
facilities.
A
catchment
basin
might
be
an
acceptable
form
of
retention
pond
for
an
onshore
facility.
Whatever
method
is
implemented,
it
must
be
capable
of
containing
the
maximum
capacity
of
any
single
compartment
of
a
tank
car
or
tank
truck
loaded
or
unloaded
in
the
facility.
A
discharge
from
the
maximum
capacity
of
any
single
compartment
of
a
tank
car
or
tank
truck
includes
a
discharge
from
the
tank
car
or
tank
truck
piping
and
hoses.
This
is
the
largest
amount
likely
to
be
discharged
from
the
oil
storage
vehicle.
A
requirement
that
secondary
containment
be
able
to
hold
only
five
percent
of
a
potential
discharge
when
procedures
are
in
place
to
prevent
discharges
fails
to
protect
the
environment
if
there
is
human
error
in
one
of
those
procedures.
In
case
of
discharge,
the
secondary
containment
system
must
be
capable
of
preventing
a
discharge
from
that
maximum
capacity
compartment
to
the
environment.
As
mentioned
above,
if
secondary
containment
is
not
practicable,
you
may
be
able
to
deviate
from
the
requirement
if
you
provide
a
contingency
plan
and
otherwise
comply
with
§112.7(
d).

Regarding
the
presence
of
personnel
(as
supervisors)
to
substitute
for
secondary
containment,
we
agree
that
spill
prevention
is
always
preferable
to
spill
containment.
However,
preventive
measures
do
not
replace
the
need
for
a
secondary
containment
system
as
these
measures
will
never
completely
eliminate
the
potential
for
a
spill
to
occur.
Such
measures,
however,
might
be
part
of
the
contingency
plan
required
when
secondary
containment
is
impracticable.

Quick
drainage
system.
A
quick
drainage
system
is
a
device
that
drains
oil
away
from
the
loading/
unloading
area
to
some
means
of
secondary
containment
or
returns
the
oil
to
the
facility.
We
note
that
this
provision
does
not
apply
to
any
UST
system
excluded
from
part
112
under
§112.1(
d)(
4).

Vehicle
drain
closure.
We
believe
that
the
requirement
to
check
vehicles
for
discharge
is
important
to
help
prevent
discharges.
If
the
check
were
not
done,
the
entire
contents
of
the
vehicle
might
be
discharged.
We
further
believe
that
the
responsibility
for
compliance
with
proposed
§112.7(
h)(
3),
as
well
as
with
all
provisions
of
the
rule,
continues
to
rest
with
the
owner
or
operator
of
the
facility
when
those
vehicles
are
loading
or
unloading
oil
at
the
facility.
If
personnel
are
not
present
to
inspect
the
vehicles,
the
owner
or
operator
must
explain
his
reasons
for
nonconformance
and
provide
equivalent
environmental
protection
by
some
other
means.
See
§112.7(
a)(
2).

X
­
K:
State
rules
­
§112.7(
j)

Background:
Section
112.7(
e)
of
the
current
rule
requires
an
owner
or
operator
to
discuss
conformance
with
§112.7
or
more
stringent
State
rules,
requirements,
and
guidelines.
In
§112.7(
i)
of
the
1991
proposed
rule
(redesignated
as
§112.7(
f)
in
the
final
rule),
we
reproposed
the
requirement
that
in
addition
to
the
minimal
prevention
220
standards
listed
under
§112.7(
c),
(e),
(f),
(g),
and
(h)
the
owner
or
operator
include
in
an
SPCC
Plan
a
complete
discussion
of
conformance
with
the
applicable
requirements
and
"other
effective
spill
prevention
and
containment
requirements
listed
in
§§
112.8,
112.9,
112.10,
and
112.11
(or,
if
more
stringent,
with
State
rules,
regulations,
and
guidelines).

Comments:
Editorial
suggestion.
We
should
move
§112.7(
i)
to
§112.7(
a)(
3).
(121)
"The
proposed
language
which
ties
this
section
to
the
requirements
in
other
sections
of
this
regulation
should
be
more
clearly
limited
to
those
sections
which
are
applicable
to
the
facility
in
question.
For
example,
requirements
in
section
112.8
...
should
not
(by
the
requirement
in
112.7(
i))
be
applied
to
any
portion
of
any
production
facility."
(L12)

Delegation.
We
should
delegate
SPCC
program
activities
to
States
or
explore
opportunities
to
enter
into
contracts
and
other
cooperative
agreements
with
States.
Delegating
responsibility
to
the
States
would
decrease
costs
to
implement
the
program,
and
the
number
of
inspections
would
increase.
(27,
52,
111,
154,
185,
193)
We
should
explore
the
possibility
of
a
grants
program
to
encourage
State
involvement.
(27,
111)

Federal
and
State
regulation.

Consistency
with
States.
Urges
"...
EPA
to
be
as
consistent
as
possible
with
rules
being
adopted
or
developed
by
Washington
and
other
states
regarding
standards
for
oil
spill
contingency
and
prevention
plans
given
federal
statutory
limitations."
(185)

DOT
rules.
Asks
why
the
proposed
requirements
are
more
restrictive
than
the
United
States
Department
of
Transportation's
(DOT's)
requirements
for
transportation­
related
facilities.
The
DOT
facilities
pose
a
higher
risk
of
discharging
oil
than
our
non­
transportation­
related
facilities.
(119)

Duplication.
Our
proposal
is
duplicative
of
other
Federal
and
State
programs,
is
confusing,
and
hinders
an
owner's
or
operator's
ability
to
comply
with
applicable
regulations.
We
should
coordinate
with
other
Federal
and
State
agencies
in
revising
the
SPCC
regulation.
(35,
42,
82,
88,
111,
133,
139,
153,
173,
185,
193)
We
should
exempt
all
facilities
currently
covered
by
other
equivalent
regulatory
programs.
(62,
173)

Environmental
overkill.
"Several
of
these
proposed
regulations
are
more
restrictive
than
State
regulations,
are
environmental
overkill,
and
would
result
in
a
facility
incurring
considerable
expense
to
come
into
compliance."
(88)

Federal
regulation
unnecessary.
"While
the
need
for
federal
regulations
is
evident
in
some
cases,
this
is
not
one
of
them.
In
many
cases,
the
proposal
overlaps
programs
already
in
place
at
the
state
level
and
thwarts
the
efforts
of
industry
to
comply
with
these
environmental
protection
programs.
Each
state
is
unique
in
its
geography,
history,
and
environmental
protection
goals.
Therefore,
if
states
deem
oil
pollution
prevention
regulations
are
necessary
to
protect
its
221
citizens,
the
states
should
be
allowed
to
draft
regulations
that
will
work
to
solve
their
own
unique
problems."
(139,
185,
193)

NPDES.
We
should
exempt
facilities
or
tanks
covered
by
a
NPDES
discharge
permit.
(35,
173)

State
regulation
unnecessary.
"With
regard
to
expense,
the
act
of
encouraging
State
and
Federal
governments
`to
supplement
the
Federal
SPCC
programs'
invites
yet
another
raid
on
the
treasuries
of
companies
through
`revenue
enhancing'
permit
fees.
Additionally,
when
blanket
`encouragements'
are
extended,
consideration
should
be
given
to
the
potential
for
a
chaotic
lack
of
uniformity
that
inevitably
results."
(45,
82)

One
plan.
We
should
require
one
plan
for
facilities
covered
under
the
Clean
Water
Act
(CWA),
the
Resource
Conservation
and
Recovery
Act
(RCRA),
and
SARA
Title
III.
(80)

Other
law.
We
should
clarify
that
an
owner
or
operator
must
comply
with
any
applicable
section
of
§§
112.8
through
112.11
provision
referenced
in
§112.7(
i).
For
example,
a
reference
in
§112.7(
i)
to
§112.8
would
apply
only
to
onshore
facilities,
excluding
production
facilities.
(L12)

Response:
Consistency
in
rules.
As
noted
above,
you
may
now
use
a
State
plan
as
a
substitute
for
an
SPCC
Plan
when
the
State
plan
meets
all
Federal
requirements
and
is
cross­
referenced.
When
you
use
a
State
plan
that
does
not
meet
all
Federal
requirements,
it
must
be
supplemented
by
sections
that
do
meet
all
Federal
requirements.
At
times
EPA
will
have
rules
that
are
more
stringent
than
States
rules,
and
some
States
may
have
rules
that
are
more
stringent
than
those
of
EPA.
If
you
follow
more
stringent
State
rules
in
your
Plan,
you
must
explain
that
is
what
you
are
doing.

Cross­
referencing
of
requirements.
In
response
to
the
commenter
who
believed
that
proposed
§112.7(
i)
(redesignated
in
today's
rule
as
§112.7(
j))
might
require
him
to
discuss
inapplicable
requirements,
we
note
that
you
must
address
all
SPCC
requirements
in
your
Plan.
You
must
include
in
your
Plan
a
complete
discussion
of
conformance
with
the
applicable
requirements
and
other
effective
discharge
prevention
and
containment
procedures
listed
in
part
112
or
any
applicable
more
stringent
State
rule,
regulation,
or
guideline.
If
a
requirement
is
not
applicable
to
a
particular
type
of
facility,
we
believe
that
it
is
important
for
an
owner
or
operator
to
explain
why.

Delegation.
We
have
no
authority
under
the
Clean
Water
Act
to
delegate
our
program
or
elements
of
it
to
the
States.
However,
States
may
enact
their
own
programs.
Government
agencies
at
the
State
and
tribal
level
often
exercise
authority
over
SPCCregulated
facilities
that
is
similar
to
EPA's
authority.
Closer
coordination
with
such
government
agencies
could
effectively
expand
SPCC's
reach
and
effectiveness
while
helping
State
and
tribal
programs
administer
their
own
activities.
This
could
be
accomplished
by
the
development
of
Memorandums
of
Understanding
(MOUs)
and
222
Interagency
Agreements
(IAGs)
with
individual
States
and
tribes.
EPA
will
also
explore
the
development
of
a
State
and
tribal
partners
program.
In
such
a
program
States
and
tribes
would
participate
on
a
voluntary
basis
and
agree
to
perform
some
program
functions
and
report
information
to
a
common
information
system
in
a
prescribed
format.
EPA
would
maintain
the
databases
and
provide
training
and
administrative
support
to
participating
States
and
tribes.
This
could
include
delivery
of
a
fuels
management
class,
and
the
sponsorship
of
training
and
conferences
in
every
region
for
States
and
tribes
to
better
understand
the
regulated
universe
and
to
better
inspect
target
facilities.
We
will
also
explore
better
data
tracking
and
sharing
with
States.

Editorial
suggestion.
We
believe
that
provision
fits
better
at
the
end
of
§112.7
than
in
§112.7(
a)(
3)
because
it
references
not
only
the
provisions
of
§112.7,
but
the
applicable
sections
of
the
part
which
follow,
as
well
as
reference
to
State
rules,
regulations,
and
guidelines.

To
simplify
the
rule
language,
we
have
amended
the
proposed
rule
to
state
that
you
must
discuss
all
applicable
requirements
in
the
Plan
instead
of
listing
all
of
the
sections
individually.

Federal
and
State
regulation.
Both
the
States
and
EPA
have
authority
to
regulate
containers
storing
or
using
oil.
We
believe
State
authority
to
regulate
in
this
area
and
establish
spill
prevention
programs
is
supported
by
section
311(
o)
of
the
CWA.
Some
States
have
exercised
their
authority
to
regulate
while
others
have
not.
We
believe
that
State
SPCC
programs
are
a
valuable
supplement
to
our
SPCC
program.
When
no
State
program
exists,
the
Federal
program
becomes
even
more
necessary.

We
also
note
that
you
may
use
NPDES
records
for
SPCC
purposes,
and
may
use
a
Best
Management
Practices
Plan
as
an
SPCC
Plan
if
it
meets
all
SPCC
requirements,
or
may
supplement
so
that
it
does.
See
§§
112.7
(introduction),
112.7(
e),
112.8(
c)(
3)(
iv),
and
112.9(
b)(
1).

We
also
note
that
our
facilities
differ
from
DOT
facilities
in
many
important
aspects,
therefore
different
rules
are
necessary.

Other
law.
Final
§112.7(
j)
refers
to
applicable
requirements
in
all
of
part
112
or
more
stringent
State
law.

Preemption.
We
do
not
preempt
State
rules,
and
defer
to
State
rules,
regulations,
and
guidelines
that
are
more
stringent
than
part
112.
223
Category
XI:
Onshore
facility
Plan
requirements
(excluding
production
facilities)

XI
­
A:
Facility
Drainage
­
§112.8(
b)

Background:
Facility
drainage.
In
1991,
we
proposed
several
changes
to
§112.7(
e)(
1)
of
the
current
rule
on
facility
drainage
at
onshore
facilities
(excluding
production
facilities).
We
proposed
to
redesignated
§112.7(
e)(
1)(
i)
through
(iv)
of
the
current
rule
as
§112.8(
b)(
1)
through
(4).
The
proposed
paragraphs
addressed
requirements
for:
facility
drainage
at
a
diked
area,
(b)(
1);
the
prohibition
on
a
flapper­
type
drain
for
diked
areas,
(b)(
2);
drainage
systems
for
undiked
areas,
and
a
diversion
system
for
a
facility
where
drainage
failed
to
meet
the
requirements
of
paragraphs
(b)(
1)­(
3),
(b)(
4).

In
1991,
we
proposed
to
redesignate
§112.7(
e)(
1)(
i)
of
the
current
rule
on
facility
drainage
from
diked
areas,
as
§112.8(
b)(
1).
We
proposed
to
redesignate
§112.7(
e)(
1)(
ii)
of
the
current
rule,
on
the
prohibition
on
flapper­
type
drains
for
diked
areas,
as
§112.8(
b)(
2).
We
left
redesignated
paragraphs
(b)(
1)
and
(2)
substantially
the
same
as
the
equivalent
provisions
in
the
current
rule.
We
proposed
to
redesignate
§112.
7(
e)(
1)(
iii)
of
the
current
rule,
on
covered
drainage
systems
for
undiked
areas,
as
§112.8(
b)(
3).
However,
in
proposed
paragraph
(b)(
3),
we
clarified
that
an
undiked
area
must
drain
into
a
pond,
lagoon,
or
catchment
basin
only
if
the
area
is
located
such
that
it
has
a
reasonable
potential
to
be
contaminated
by
an
oil
discharge.
We
also
proposed
to
recommend
­­
rather
than
require
­­
that
an
owner
or
operator
avoid
placing
a
catchment
basin
in
an
area
subject
to
periodic
flooding.
We
proposed
to
redesignated
§112.7(
e)(
1)(
iv)
of
the
current
rule
as
§112.8(
b)(
4).
In
paragraph
(b)(
4),
we
proposed
a
requirement
that
at
a
facility
without
a
drainage
system
described
in
paragraphs
(b)(
1)
through
(3),
a
diversion
system
must
retain
oil
in
the
facility,
rather
than
return
oil
to
the
facility
after
the
oil
already
was
discharged.

XI­
A(
1)
Diked
storage
area
drainage
­
§112.8(
b)(
1)

Comments:
Applicability.
"Broadly
read
this
could
require
a
pond
or
lagoon
to
capture
drainage
from
every
inch
of
our
manufacturing
facilities."
Suggests
limiting
proposal
to
"areas
with
potential
to
receive
spills
from
tanks
greater
than
660
gallons
or
areas
with
tanks
regulated
under
these
rules."
(126)

Electrical
equipment.
The
diked
storage
area
drainage
requirement
should
not
apply
to
electrical
utility
systems
(such
as
lubrication
systems
and
hydraulic
lift
systems)
that
use
oil
for
operational
purposes.
We
should
not
regulate
these
systems
as
we
would
regulate
a
storage
tank.
(125)

Secondary
containment.
"For
facilities
with
site­
wide
containment,
or
that
have
substantial
storm
water
draining
onto
and
across
the
site,
providing
such
detention
is
not
practical,
and,
...
,
may
encourage/
justify
reliance
on
contingency
plans
in
lieu
of
containment."
(76)
224
De
minimis
amounts
of
oil.
It
would
be
impossible
for
owners
or
operators
to
ensure
that
"no
oil"
would
be
discharged
into
water
from
diked
areas,
because
the
human
eye
is
incapable
of
perceiving
minute
amounts
of
oil
in
water.
We
should
create
a
more
objective
standard,
such
as
the
"oil
sheen"
standard
that
appears
in
40
CFR
110.3.
(125)

Oil/
water
separators.
"The
use
of
oil
water
separators,
underflow
uncontrolled
discharge
devices,
and
other
apparatus
can
substantially
reduce
the
potential
of
a
significant
spill
of
floating
or
other
products
which
can
be
separated
by
gravity."
(76,
125)

Response:
Applicability.
We
disagree
that
we
should
limit
the
scope
of
this
section
to
facilities
having
areas
with
the
potential
to
receive
discharges
greater
than
660
gallons
or
areas
with
tanks
regulated
under
these
rules.
Small
discharges
(that
is,
of
660
gallons
or
less)
as
described
in
§112.1(
b)
from
diked
storage
areas
can
cause
great
environmental
harm.
See
section
III.
F
of
the
preamble
to
today's
rule
for
a
discussion
of
the
effects
of
small
discharges.
We
disagree
that
this
section
should
apply
only
to
areas
with
tanks
regulated
under
these
rules
because
this
rule
applies
to
regulated
facilities,
not
merely
areas
with
regulated
tanks
or
other
containers.
A
facility
may
contain
operating
equipment
within
a
diked
storage
area
which
could
cause
a
discharge
as
described
in
§112.1(
b).

We
disagree
that
the
requirement
is
not
practical
for
facilities
with
site­
wide
containment,
or
that
have
substantial
storm
water
draining
onto
and
across
the
site.
Where
oil/
water
separators,
underflow
uncontrolled
discharge
devices,
or
other
positive
means
provide
equivalent
environmental
protection
as
the
discharge
restraints
required
by
this
section,
you
may
use
them,
if
you
explain
your
reasons
for
nonconformance.
See
§112.7(
a)(
2).
However,
you
must
still
ensure
that
no
oil
will
be
discharged
when
using
alternate
devices.

De
minimis
amounts
of
oil.
This
rule
is
concerned
with
a
discharge
of
oil
that
would
become
a
discharge
as
described
in
§112.1(
b).
When
oil
is
present
in
water
in
an
amount
that
cannot
be
perceived
by
the
human
eye,
the
discharge
might
not
meet
the
description
provided
in
40
CFR
110.3.
Therefore,
such
a
discharge
might
not
be
a
discharge
in
a
quantity
that
may
be
harmful,
and
therefore
not
a
reportable
discharge
under
part
110.
However,
a
discharge
which
is
invisible
to
the
human
eye
might
also
contain
components
(for
example,
dissolved
petroleum
components)
which
would
violate
applicable
water
quality
standards,
making
it
a
reportable
discharge.
Therefore,
we
are
keeping
the
language
as
proposed,
other
than
making
some
editorial
changes.

XI­
A(
2)
Diked
storage
areas
­
valves
used;
inspection
of
retained
stormwater

112.8(
b)(
2)

Comments:
Innovative
devices.
"This
section
should
be
modified
to
make
clear
whether
drainage
systems
that
allow
the
passage
of
water
but
not
oil,
such
as
drains
equipped
with
imbiber
beads,
may
be
used
for
facility
drainage."
(39,
76,125)
225
Response:
Innovative
devices.
This
rule
does
not
preclude
innovative
devices
that
achieve
the
same
environmental
protection
as
manual
open­
and­
closed
design
valves.
If
you
do
not
use
such
valves,
you
must
explain
why.
The
provision
for
deviations
in
§112.7(
a)(
2)
allows
alternatives
if
the
owner
or
operator
states
his
reasons
for
nonconformance,
and
provides
equivalent
environmental
protection
by
some
other
means.
However,
you
may
not
use
flapper­
type
drain
valves
to
drain
diked
areas.
And
if
you
use
alternate
devices
to
substitute
for
manual,
open­
and­
closed
design
valves,
you
must
inspect
and
may
drain
retained
storm
water,
as
provided
in
§112.8(
c)(
3)(
ii),
(iii),
and
(iv),
if
your
facility
drainage
drains
directly
into
a
watercourse,
lake,
or
pond
bypassing
the
facility
treatment
system.

XI­
A(
3)
Drainage
from
undiked
areas
­
§112.8(
b)(
3)

Comments:
Support
for
proposal.
We
should
permit
facility
drainage
systems
from
undiked
areas
to
flow
into
ponds,
lagoons,
or
catchment
basins
designed
to
retain
spilled
oil
or
into
the
plant
water
treatment
system,
if
that
system
is
designed
to
retain
spilled
oil.
(121)
"Section
112.8(
b)(
3)
clearly
envisions
and
allows
for
facilities
which
have
undiked
oil
storage
areas
and
provides
a
standard
for
the
capture
of
any
spill
from
such
areas
through
the
use
of
catchment
basins,
lagoons
and
the
like
using
a
design
of
the
facility's
choosing.
Velsicol
supports
such
a
standard
for
undiked
oil
storage
areas."
(L26)

Catchment
basins.
"It
is
highly
unlikely
that
catchment
basins
will
operate
effectively
during
a
flood
event.
Since
these
types
of
facilities
could
cause
significant
harm
to
the
environment,
EPA
should
require
that
catchment
basins
not
be
located
in
areas
subject
to
flooding."
(12)
"Catchment
basins
in
areas
subject
to
flooding
essentially
ensure
eventual
surface
water
contamination.
The
proposed
regulations
should
be
expanded
to
require
that
no
new
facilities
used
for
oil
or
hazardous
substance
storage
are
sited
in
floodplains,
and
drainage
systems
for
existing
facilities
are
engineered
(even
if
it
requires
pumping
of
contaminated
water
to
a
higher
level
for
storage
prior
to
treatment)
so
that
minimal
amounts
of
contaminated
water
are
retained
in
areas
subject
to
periodic
flooding."
(44)

Applicability
­
generally.
We
should
require
facility
drainage
systems
from
undiked
areas
to
flow
into
a
pond,
lagoon,
or
catchment
basin
"where
possible"
or
"if
practicable."
(54)
It
is
impossible
to
specify
what
constitutes
proper
drainage
control
for
all
types
of
facilities.
Therefore,
we
should
retain
the
verb
"should"
as
in
the
current
rule
"to
allow
for
the
exercise
of
good
engineering
practice."
(125)

Electrical
equipment.
"It
would
be
very
impractical
to
divert
flow
across
an
entire
site
to
a
pond,
lagoon
or
catchment
basin
where
such
flow
is
currently
uncollected
or,
if
collected,
is
diverted
to
a
storm
drainage
system
prior
to
discharge.
Indeed,
for
electrical
equipment,
there
is
an
inherent
inconsistency
between
the
drainage
requirements
of
proposed
§112.8(
b)(
3)
and
the
secondary
containment
exclusion
of
proposed
§112.8(
c)(
2).
...
A
suggested
method
for
reducing
the
impracticality
and
inconsistency
of
the
proposed
requirement
is
to
226
limit
the
applicability
of
§112.
8(
b)(
3)
to
"systems
with
a
potential
for
oil
spill
`discharge'
into
or
upon
the
navigable
waters
of
the
United
States
rather
than
the
broader
and
more
encompassing
potential
for
`contamination'."
(100)
The
drainage
requirements
would
impose
a
substantial
financial
burden
on
facility
owners
or
operators
and
the
burden
on
the
electrical
utility
industry
would
outweigh
the
environmental
benefits.
(125)
In
urban
areas,
it
would
be
impossible
for
owners
or
operators
to
meet
the
drainage
requirements
for
transformers
in
vaults
in
large
office
and
apartment
buildings,
and
underneath
urban
streets.
"Similarly,
there
is
simply
no
space
at
such
sites
to
construct
the
drainage
control
structures
required
by
the
proposal."
(125,
189)

Alternatives.
"If
it
is
the
intent
of
the
US
EPA
to
require
catchment
for
such
areas,
the
operator
should
have
the
option
of
providing
spill
control
by
committing
to
the
regular
inspection
of,
and
immediate
clean­
up
of
spills,
within
such
areas."
(76)
Asks
clarification
as
to
whether
a
properly
sized
and
operated
oil/
water
separator
meets
the
§112.8(
b)(
3)
requirement
for
drainage
control.
(92,
125)

Response:
Support.
We
appreciate
commenter
support.

Applicability.
We
disagree
that
the
rule
language
should
become
a
recommendation
because
we
believe
that
it
is
important
to
control
the
potential
discharges
the
rule
addresses.
The
rule
does
this
by
requiring
retention
of
water
within
the
facility
from
undiked
areas
if
there
is
no
provision
for
flow
into
ponds,
lagoons,
or
catchment
basins
designed
to
retain
oil
or
return
it
to
the
facility.
Where
a
diversion
system
is
infeasible,
if
you
explain
your
reasons
for
nonconformance,
you
may
provide
equivalent
environmental
protection
by
an
alternate
means.

In
response
to
the
commenter
who
questioned
the
applicability
of
this
paragraph
to
areas
under
aboveground
piping
and
loading/
unloading
areas,
we
note
that
both
areas
are
subject
to
the
rule's
requirements
if
they
are
undiked.

Electrical
equipment.
The
requirements
of
paragraph
(b)(
3)
apply
to
a
facility
with
electrical
equipment.
If
you
determine
it
is
infeasible
to
comply
with
the
requirements
of
the
paragraph,
you
must
explain
your
reasons
for
nonconformance,
and
provide
equivalent
environmental
protection.
40
CFR
112.7(
a)(
2).

Alternatives.
The
rule
does
not
limit
you
to
the
use
of
drainage
trenches
for
undiked
areas.
Other
forms
of
secondary
containment
may
be
acceptable.
The
rule
only
prescribes
requirements
for
the
drainage
of
diked
areas,
but
does
not
mandate
the
use
of
diked
areas.
However,
if
you
do
use
diked
areas,
the
rule
prescribes
minimum
requirements
for
drainage
of
those
areas.
Also,
if
the
requirement
is
not
practical,
you
may
explain
your
reasons
for
nonconformance
and
provide
equivalent
environmental
protection
under
§112.7(
a)(
2).

XI­
A(
4)
Diversion
systems
­
§112.8(
b)(
4)
227
Comments:
"Ohio
EPA
agrees
with
the
proposed
language
regarding
facility
drainage.
The
proposed
language
requires,
rather
than
suggests,
that
facility
drainage
flow
to
a
catchment
basin,
Also,
oil
is
to
be
`retained'
at
the
facility,
rather
than
`returned.
'
While
we
understand
that
this
change
implies
that
the
spill
should
not
leave
the
facility
boundaries,
it
should
be
further
clarified."
(27)
We
should
require
the
owner
or
operator
either
to
retain
oil
within
the
facility
or
return
it
to
the
facility,
whichever
is
applicable.
The
diversion
system
requirement
should
apply
only
to
the
"petroleum
areas
of
the
facility
such
as
tanks,
pipes,
racks,
and
diked
areas"
because
"drainage
from
the
rest
of
the
facility
should
not
be
contaminated
and
thus
should
not
have
to
be
diverted."
(54)

Response:
The
rule
accomplishes
the
aim
of
retaining
within
the
facility
minimal
amounts
of
contaminated
water
in
undiked
areas
subject
to
periodic
flooding.
It
is
better
that
a
diversion
system
retain
rather
than
allow
oil
to
leave
the
facility,
thus
enhancing
the
prevention
goals
of
the
rule.
Furthermore,
it
should
be
easier
to
retain
discharged
oil
rather
than
retrieve
oil
that
has
been
discharged
from
the
facility.
Therefore,
we
agree
with
the
commenter
that
"retained"
oil
is
oil
that
never
leaves
the
facility.
We
also
agree
that
the
rule
applies
only
to
drainage
from
the
"petroleum"
(or
other
oil)
areas
of
the
facility
such
as
tanks,
pipes,
racks,
and
diked
areas,
because
the
purpose
of
the
SPCC
rule
is
to
prevent
discharges
of
oil,
not
of
all
runoff
contaminants.
Amendment
of
the
rule
language
is
unnecessary
because
all
of
the
rule
applies
only
to
"petroleum"
or
"oil"
areas
of
the
facility.
Therefore,
we
have
promulgated
the
rule
language
as
proposed
with
a
minor
editorial
change.

XI­
A(
5)
Drainage
systems
­
§112.8(
b)(
5)

Comments:
PE
certification.
We
should
add
a
section
to
the
rule
requiring
that
Professional
Engineers
(PEs)
certify
the
design
and
construction
of
the
storm
water
drainage
system
and
the
sanitary
sewer
system,
because
the
PE
is
in
the
best
position
to
prepare
the
spill
containment
parts
of
the
SPCC
Plan.
(47)

Response:
PE
certification.
PE
certification
is
already
required
for
the
design
of
stormwater
drainage
and
sanitary
sewer
systems
by
current
rules
because
those
systems
are
a
technical
element
of
the
Plan.
Therefore,
we
are
keeping
the
language
as
proposed.

XI­
A(
6)
FEMA
requirements
­
Proposed
§112.8(
b)(
6)

Comments
for
this
section
were
combined
with
comments
for
section
XII­
D.

XI
­
B:
Bulk
storage
containers
­
§112.8(
c)

XI­
B(
1)
Material
and
construction
­
§112.8(
c)(
1)

Background:
Section
112.7(
e)(
2)(
i)
of
the
current
rule
(redesignated
as
§112.8(
c)(
1)
of
the
final
rule)
requires
an
owner
or
operator
of
an
onshore
bulk
storage
facility
to
ensure
228
that
the
material
and
construction
of
tanks
used
to
store
oil
are
compatible
with
the
material
stored
and
conditions
of
storage.
In
§112.8(
c)(
1),
we
proposed
a
new
recommendation
that
the
construction,
materials,
installation,
and
use
of
tanks
conform
with
relevant
portions
of
industry
standards
such
as
API,
NFPA,
UL,
or
ASME
standards.

Comments:
Support
for
proposal.
"Based
on
the
preamble,
it
is
apparent
that
the
use
of
industry
standards
is
intended
to
be
a
recommendation
and
not
a
requirements.
Valvoline
fully
supports
the
use
of
standards
in
this
manner
as
they
were
not
developed
for
use
as
regulatory
requirements
and
are
not
applicable
or
necessary
in
all
possible
situations.
As
a
result,
their
use
should
be
discretionary
utilizing
good
engineering
practices
as
appropriate.
However,
the
wording
utilized
in
section
112.
8(
c)(
1)
taken
in
conjunction
with
section
112.7(
a)
is
contradictory
as
to
whether
or
not
the
use
of
industry
standards
is
a
recommendation
or
a
requirement."
(67,
95,
102,
115,
148)

Opposition
to
proposal.
We
should
not
place
recommendations
in
the
regulation.
We
should
not
ask
owners
or
operators
to
consider
good
engineering
practice
since
this
makes
the
regulation
unenforceable.
Instead,
we
should
tell
the
owner,
operator,
or
certifying
engineer
what
good
engineering
practice
requires.
We
should
substitute
proposed
§112.8(
c)(
2)
with
the
proposed
§112.8(
c)(
1)
text
and
delete
the
recommendation,
which
is
"advisory
and
unenforceable."
(121)

Additional
industry
standards.
In
§112.8(
c)(
1),
we
should
reference
the
Steel
Tank
Institute
(STI)
standard
F911­
91,
"Standard
for
Unitized
Steel
Aboveground
Storage
Tank
Systems
with
Open
Top
Secondary
Containment."
(140)
The
industry
standards
listed
in
the
preamble
are
"extremely
important,"
but
these
standards
do
not
address
the
physical
site
and
its
surrounding
lands
and
waters.
(L4)

Requirement
instead.
The
rule
should
require,
not
recommend,
that
tanks
meet
industry
standards.
"At
a
date
certain,
all
existing
tanks
should
be
upgraded
to
meet
industry
codes.
Moreover,
all
new
and
reconstructed
tanks
should
be
subject
to
applicable
codes."
(44)
We
should
change
§112.8(
c)(
1)
to
require
the
following:
"All
tanks
constructed
after
the
effective
date
of
this
part
must
be
constructed
to
one
of
the
following
industry
standards
(list
here
the
standards
acceptable
to
EPA).
The
owner
or
operator
shall
retain
records,
as
part
of
the
(SPCC
Plan),
to
show
which
standard
was
used
in
the
construction
of
the
tank,
and
a
certification
plate,
setting
forth
the
standard
to
which
the
tank
was
constructed
and
the
date
of
its
construction
shall
be
permanently
affixed
to
the
tank."
(121)

Response:
Requirement
v.
recommendation.
The
first
sentence
of
the
proposed
rule
indeed
contemplated
a
requirement,
i.
e.,
that
no
container
may
be
used
for
the
storage
of
oil
unless
its
material
and
construction
are
compatible
with
the
material
stored
and
the
conditions
of
storage,
such
as
pressure
or
temperature.
The
second
sentence,
which
was
clearly
a
recommendation,
has
been
deleted
from
the
rule
because
we
have
decided
to
remove
all
recommendations
from
the
rule
language.
Rules
are
mandates,
and
we
do
not
wish
to
confuse
the
regulated
community
as
to
what
actions
are
229
mandatory
and
what
actions
are
discretionary.
The
Professional
Engineer
must,
pursuant
to
§112.3(
d)(
1)(
iii),
certify
that
he
has
considered
applicable
industry
standards
in
the
preparation
of
the
Plan.
While
he
must
consider
such
standards,
use
of
any
particular
standards
are
a
matter
of
good
engineering
practice.

Additional
industry
standards.
While
we
do
not
specify
particular
standards
in
the
rule,
we
endorse
the
use
of
industry
standards.
We
note
that
the
discussion
of
many
sections
of
the
rule
addresses
particular
industry
standards.

Section
112.8(
c)(
2).
We
will
address
issues
relating
to
§112.8(
c)(
2)
under
the
discussion
of
that
section.

XI
­
B(
2)
Secondary
containment
for
bulk
storage
containers
at
onshore
facilities
­
§112.8(
c)(
2)

Background:
In
1991,
we
proposed
to
redesignated
the
§112.7(
e)(
2)(
ii)
secondary
containment
requirements
of
the
current
rule
as
§112.8(
c)(
2),
and
make
some
revisions.
We
gave
notice
in
the
preamble
that
"sufficient
freeboard"
to
contain
precipitation
is
freeboard
sufficient
to
contain
a
25­
year
storm
event.
We
also
proposed
that
diked
areas
be
sufficiently
impervious
to
contain
spilled
oil
for
at
least
72
hours.
The
rationale
for
the
72­
hour
standard
was
to
allow
time
for
the
discovery
and
removal
of
a
discharge.

Electrical
equipment.
In
the
1991
preamble,
we
noted
that
certain
facilities
may
have
equipment
such
as
electrical
transformers
that
contain
significant
quantities
of
oil
for
operations
rather
than
for
storage.
For
safety
and
other
considerations,
we
determined
that
we
should
not
require
an
owner
or
operator
of
such
oil­
filled
equipment
to
comply
with
§112.8(
c)
or
§112.9(
d)
secondary
containment
requirements,
because
storage
of
oil
in
bulk
is
not
the
primary
purpose
of
such
equipment.
Therefore,
we
stated
that
an
owner
or
operator
of
a
facility
with
equipment
containing
oil
for
ancillary
purposes
does
not
need
to
provide
secondary
containment
for
this
equipment
or
implement
the
other
provisions
of
proposed
§112.8(
c)
(or
§112.9(
d).
56
FR
54623.
However,
an
owner
or
operator
of
oil­
filled
equipment
must
meet
other
applicable
SPCC
requirements
including
the
requirements
of
§112.7(
c),
to
provide
appropriate
containment
and
diversionary
structures
to
prevent
discharged
oil
from
reaching
navigable
waters.

Comments:
De
minimis
containers.
"Request
that
some
de
minimis
limit
be
set
for
requiring
secondary
containment.
While
in
some
cases
secondary
containment
for
the
largest
tank
is
acceptable,
can
manufacturers
may
have
several
smaller
tanks,
none
of
which
should
be
considered
large."
(62)

Designations.
"In
extraordinary
circumstances,
EPA
Solid
Waste
and
Emergency
Response
should
designate
local
fire
regulatory
authorities
and/
or
state
and
local
EPA's
to
make
decisions
concerning
`deemed
equivalency'
for
secondary
containment,
as
is
done
by
the
UST
section
of
EPA."
(65)
230
Double­
walled
or
vaulted
tanks.
We
should
allow
an
owner
or
operator
to
use
prefabricated
vaulted,
or
double­
walled
tanks
with
secondary
containment
under
§112.8(
c).
(65,
79,
140,
144,
179)

Facility
size.
"Recognizing
EPA's
limited
funding
and
enforcement
resources,
EPA
should
consider
allowing
the
state
EPA's
and
the
fire
regulatory
authorities
to
continue
to
regulate
the
small
`throughput'
vaulted
tank
industry
which
fire
regulatory
authorities
have
defined
as
6,000
per
tank
and
18,000
gallons
per
site."
(65,
79)

Fire
codes.
"Deem
as
equivalent
for
EPA
purposes,
the
secondary
containment
of
VAST
technology
which
meets
any
of
EPA­
recognized
industry
standards
of
the
model
fire
codes
of
NFPA,
BOCA,
or
UFC."
(65)

Freeboard.
Double­
walled
steel
tanks
with
integral
secondary
containment,
and
other
factory­
fabricated
tanks
with
secondary
containment
are
designed
so
that
precipitation
does
not
collect
within
the
secondary
containment.
(65,
140)
Asks
us
to
address
the
technical
construction
design
of
steel
tanks
with
factoryfabricated
secondary
containment
in
the
§112.8(
c)(
2)
freeboard
requirements.
(140)
A
double­
walled
"F921­
92"
AST
or
its
equivalent
does
not
need
freeboard
because
it
is
entirely
enclosed;
the
outside
tank
is
larger
than
the
inside
tank
and
will
hold
the
entire
contents
of
the
primary
tank.
(179)

Impermeability.
VASTs
are
impervious
to
oil
for
72
hours.
(65)

Outer­
steel
wrap.
The
secondary
containment
provided
by
a
factory­
fabricated,
"integral
outer­
steel
wrap"
is
acceptable
if
the
system
has
additional
mechanisms
to
prevent
overfill
and
provide
containment.
(140)

Regional
opposition.
"Working
mostly
with
fire
prevention
personnel
and
codes,
but
with
environmental
protection
of
equal
concern,
several
styles
of
tanks
have
been
developed
which
will
meet
the
intent
of
the
proposed
regulations
for
protection
of
the
environment,
but
based
on
an
interpretation
from
Region
10
have
not
ben
allowed
to
be
used."
(108,
122)

Vandalism
and
fire.
A
VAST's
concrete
encasement
provides
protection
against
vandalism
and
fire.
VASTs
allow
an
owner
or
operator
to
dike
the
contents
of
every
tank,
rather
than
only
the
single
largest
tank.
(65)

Editorial
suggestions.
Recommends
that
we
move
the
proposed
§112.8(
c)(
2)
on
secondary
containment
requirements
to
the
proposed
§112.8(
c)(
3)
on
drainage
requirements.
Asks
that
we
change
the
phrase
"all
bulk
storage
tank
installations"
to
"tanks"
in
the
proposed
§112.8(
c)(
2)
sentence,
"All
bulk
storage
tank
installations
should
be
constructed
so
that
a
secondary
means
of
containment
is
provided
for
the
entire
contents
of
the
largest
single
tank
and
sufficient
freeboard
to
allow
for
precipitation."
(121)
231
Electrical
or
other
operating
equipment.
Support
for
proposal
that
an
owner/
operator
who
has
equipment
containing
oil
for
ancillary
purposes
need
not
have
secondary
containment
nor
comply
with
the
§112.8(
c)
and
§112.9(
d)
bulk
storage
container
provisions.
(66,
103,
125,
132,
134,
156,
164,
L7,
L20)

Fire,
hazard,
safety
considerations.
Installing
secondary
containment
for
electrical
equipment
may
create
electrical
and
fire
hazards.
(125)
We
should
clarify
what
"safety
and
other
considerations"
make
it
appropriate
to
exclude
electrical
equipment
from
secondary
containment
requirements.
(L17)

Leak
detection.
An
owner
or
operator
can
immediately
detect
a
leak
from
electrical
equipment
because
a
leak
would
trigger
the
alarm
system.
(66,
98,
138,
L20)
Electrical
equipment
is
constructed
with
pressure
relief
devices
and
that
a
leak
from
one
unit
would
not
affect
another
unit.
(L20)

Operating
equipment.
We
should
exclude
from
the
secondary
containment
requirements:
trash
compactors
and
process
or
water
pumps;
lubricating
oil
used
in
engines,
turbines,
compressors,
and
expanders;
oil
circuit
breakers
and
auto
boosters;
oil
held
temporarily
in
the
internal
or
external
storage
compartment
of
an
oil/
water
separator;
oil
used
in
cranes,
jacks,
elevators,
and
forklifts;
hydraulic
lift
systems;
throughput­
type
tanks;
wastewater
treatment
tanks;
and
capacitors
and
oil­
based
heaters.
(62,
65,
66,
102,
107,
125,
132,
L7)

Manifolded
tanks.
"The
term
`single
largest
tank'
should
be
modified
to
include
tanks
which
are
manifolded
together,
or
otherwise
have
overflow
capabilities."
(27)

Seventy­
two­
hour
impermeability
standard.
See
the
discussion
on
§112.7(
c)
for
the
comments
on
this
subject.

Secondary
containment,
in
general.

Supports
requirement.
Secondary
containment
for
storage
containers,
including
mobile
storage
containers,
should
be
adequate
to
contain
the
contents
of
the
largest,
single
tank
within
the
secondary
containment
with
freeboard
sufficient
for
precipitation
from
a
25­
year
storm
event.
The
State
of
New
Jersey
has
this
requirement.
(27,
147)

Opposes
requirement.
Requiring
secondary
containment
for
small
ASTs
is
unduly
burdensome
and
impractical,
and
would
require
owners
or
operators
to
staff
and
monitor
otherwise
unstaffed
sites.
(69)
Asks
us
to
consider
promulgating
a
"more
realistic"
provision
for
secondary
containment
systems
(71).
We
have
no
justification
for
requiring
an
owner
or
operator
to
provide
secondary
containment
for
the
contents
of
the
largest
single
tank,
or
for
requiring
an
owner
or
operator
to
provide
freeboard
sufficient
to
allow
for
precipitation.
The
commenter
cited
our
"Analysis
of
Implementing
Permitting
Activities
for
Stormwater
Discharges
Associated
with
Industrial
Activity"
document
as
evidence
232
of
the
minimal
risk
posed
by
secondary
containment
overflow
(July
1991).
(173)
We
should
recognize
that
secondary
containment
installation
is
not
possible
for
all
tanks
(e.
g.,
indoor
tanks).
(175)

Contingency
planning
instead.
Asks
us
to
follow
the
Federal
Aviation
Administration's
example,
and
allow
an
owner
or
operator
of
a
facility
with
"small
numbers
of
small
capacity
ASTs"
to
conduct
contingency
planning
and
training
instead
of
installing
secondary
containment.
We
should
use
the
fire
prevention
code
to
define
the
term
"small
numbers
of
small
capacity
ASTs"
as
"less
than
a
total
capacity
of
6,
000
gallons
per
facility."
(69)

Largest
single
tank.
Not
all
facilities
"have
enough
property
to
provide
this
volume
of
containment,"
which
would
result
in
an
enormous
operational
burden
for
existing
facilities.
However,
we
should
require
secondary
containment
for
existing
tanks
with
a
volume
greater
than
100,000
gallons.
(90)
"Impervious
containment
of
a
volume
larger
than
the
largest
single
tank
may
not
be
necessary
for
all
tanks."
(90,126)

Methods.
"In
other
words,
we
recommend
that
the
free
choice
of
design
offered
to
the
facility
by
112.
8(
b)(
3)
be
preserved
in
112.
8(
c)(
2)
and
not
be
narrowed
to
allow
only
drainage
trench
enclosures
in
cases
where
diking
is
not
used."
(L26)

Oil/
water
separators.
Asks
us
to
allow
properly
sized
and
operated
oil/
water
separators
to
meet
the
drainage
control
and
secondary
containment
requirements.
(98)

Phase­
in.
We
should
phase­
in
secondary
containment
requirements,
and
apply
them
to
large
facilities
only.
(116)

Underground
cable
systems.
"Even
if
secondary
containment
systems
could
be
installed,
the
costa
are
likely
to
be
prohibitive.
...
Electric
utilities
already
have
operational
response
plans
to
address
leaks
as
part
of
their
planning
to
prevent
disruption
of
service."
(125)

"Should
to
shall"
cost.
We
reduced
the
impact
of
the
proposal
by
failing
to
consider
the
cost
of
changing
"should"
to
"shall,"
and
cited
the
secondary
containment
requirement
as
an
example.
The
proposed
rule
requires
an
owner
or
operator
to
equip
all
tank
batteries
with
secondary
containment,
although
many
petroleum
extraction
industry
tank
batteries
do
not
have
secondary
containment
because
of
the
cost
or
lack
of
need.
(L27)

Snow
and
ice.
"In
the
case
of
many
Rocky
Mountain
fields,
secondary
containment
in
the
form
of
dikes
is
worthless
because
of
drifting
snow
which
turns
to
ice
filling
the
diked
area."
(L27)

Sufficient
freeboard.
233
Alternatives
to
freeboard.
"Also,
the
regulations
should
specify
that
maintaining
any
freeboard
does
not
apply
when
rainguards
are
used
to
divert
storm
water
and
keep
it
from
accumulating
in
the
diked
area."
(88)
"E&
P
operations
should
have
the
option
to
use
portable/
permanent
pumps
or
water
hauler
trucks
for
removal
of
any
25
year
storm
water
event.
KMS
believes
the
more
appropriate
and
applicable
standard
is
the
10­
year
event."
(114)

Clarification
needed.
We
should
clarify
what
we
mean
in
§112.8(
c)(
2)
by
"sufficient
freeboard."
(54,
154,
179,
L18)

10­
year
storm
event.
It
would
be
adequate
to
provide
freeboard
sufficient
to
contain
precipitation
from
a
10­
year
storm
event,
or
more
specifically,
a
10­
year,
24­
hour
storm
event.
(48,
80,
87,
95,
102,
114,
133,
L3,
L12)

25­
year
storm
event.

Opposes
recommendation.
"It
will
be
difficult
and
would
require
meteorological
studies
over
a
period
of
time
to
determine
what
freeboard
is
sufficient
to
contain
a
25
year
storm
event."
(34,
53)
"We
should
consider
as
sufficient,
a
tank's
ability
to
contain
110
percent
of
the
capacity
of
the
largest
tank,
which
is
an
accepted
industry
standard
and
consistent
with
good
engineering
practice.
(34,
48,
54,
133,
L7)
"We
feel
that
the
25
year
storm
containment
recommendation
is
unduly
stringent,
and
would
impose
considerable
costs
without
any
significant
benefits."
(80)
We
should
allow
flexibility
for
determining
whether
a
facility
has
adequate
freeboard.
There
is
not
enough
space
to
retrofit
the
containment
areas
required
to
provide
freeboard
for
a
25­
year
storm
for
all
facilities.
(88)
"The
chances
of
a
secondary
containment
dike
being
full
of
oil
at
the
same
time
that
a
24­
hour,
25­
year
storm
event
takes
place
is
astronomically
small.
Freeboard
capable
of
holding
a
24­
hour,
10­
year
storm
event
is
sufficient."
(102)
The
volume
from
a
25­
year
storm
event
should
remain
as
a
recommendation,
but
we
should
not
specify
the
amount
of
precipitation
accumulated
from
a
25­
year
storm
event
because
it
will
vary
depending
on
the
location.
States
may
require
a
specific
freeboard
capacity.
(143)
"The
rubber
industry
is
concerned
that
the
25­
year
freeboard
`recommendation'
will
be
interpreted
as
a
`requirement'."
(L3)
"This
`requirement'
may
be
sufficient
for
new
storage
tanks.
Secondary
containment
for
previously
installed
tanks,
however,
may
have
been
designed
for
100%
of
the
largest
tank,
110%
of
the
largest
tank,
100%
of
the
largest
tank
plus
0.5
inches
of
rain,
or
another
viable
measure.
EPA
should
provide
some
variance
to
allow
existing
containment
to
meet
the
intent
of
the
law,
and
thereby
not
requiring
small
additions
to
the
containment
structure
with
minimum
resulting
benefit."
(L7)

Clarification
needed.
We
should
clarify
what
we
meant
by
"sufficient
to
contain
a
25­
year
storm
event."
(54)
Asks
clarification
of
the
duration
and
the
recurrence
frequency
of
the
25­
year
storm
event.
(76,
87,
102,
114)
234
Response:
De
minimis
containers.
We
have
established
a
de
minimis
container
size
of
less
than
55
gallons.
You
do
not
have
to
provide
secondary
containment
for
containers
of
less
than
55
gallons.

Designations.
We
disagree
that
we
should
designate
State
and
local
authorities
to
determine
whether
a
tank
meets
the
§112.8(
c)
secondary
containment
requirements.
We
have
no
authority
under
the
Clean
Water
Act
to
delegate
elements
of
the
SPCC
program
to
State
or
local
governments.
We
likewise
disagree
that
we
should
that
we
should
designate
Federal
authorities,
including
our
regional
offices,
to
determine
whether
a
container
meets
the
§112.8(
c)
secondary
containment
requirements.
Such
a
determination
is
in
the
first
instance
one
for
the
owner
or
operator
to
make
in
consultation
with
his
Professional
Engineer.
If
the
Regional
Administrator
disagrees
with
this
determination,
he
may
require
the
owner
or
operator
to
amend
his
Plan.

Double­
walled
or
vaulted
tanks.
The
term
"vaulted
tank"
has
been
used
to
describe
both
double­
walled
tanks
(especially
those
with
a
concrete
outer
shell)
and
tanks
inside
underground
vaults,
rooms,
or
crawl
spaces.
While
double­
walled
or
vaulted
tanks
are
subject
to
secondary
containment
requirements,
shop­
fabricated
double­
walled
aboveground
storage
tanks
equipped
with
adequate
technical
spill
and
leak
prevention
options
might
provide
sufficient
equivalent
secondary
containment
as
that
required
under
§112.7(
c).
Such
options
include
overfill
alarms,
flow
shutoff
or
restrictor
devices,
and
constant
monitoring
of
product
transfers.
In
the
case
of
vaulted
tanks,
the
Professional
Engineer
must
determine
whether
the
vault
meets
the
requirements
for
secondary
containment
in
§112.7(
c).
This
determination
should
include
an
evaluation
of
drainage
systems
and
of
sumps
or
pumps
which
could
cause
a
discharge
of
oil
outside
the
vault.
Industry
standards
for
vaulted
tanks
often
require
the
vaults
to
be
liquid
tight,
which
if
sized
correctly,
may
meet
the
secondary
containment
requirement.

There
might
also
be
other
examples
of
such
alternative
systems.
Larger,
field­
erected
tanks
(generally
over
12,000
gallons)
should
not
be
without
more
traditional
forms
of
secondary
containment
as
listed
in
§112.7(
c)
because
of
the
higher
risk
of
uncontrolled
discharges
from
such
tanks
due
to
tank
size,
design,
and
pumping
rates.

Editorial
suggestions.
We
disagree
that
we
move
should
§112.8(
c)(
2)
secondary
containment
requirements
to
§112.8(
c)(
3)
with
drainage
requirements.
Drainage
and
secondary
containment
are
discrete
subjects
which
should
be
handled
separately.

In
the
first
sentence,
"spill"
becomes
"discharge."
Also
in
that
sentence,
"contents
of
the
largest
single
tank"
becomes
"capacity
of
the
largest
single
container."
This
is
merely
a
clarification
and
has
always
been
the
intent
of
the
rule.
The
contents
of
a
container
may
vary
from
day
to
day,
but
the
capacity
remains
the
same.
In
discussing
capacity,
we
noted
in
the
1991
preamble
that
"the
oil
storage
capacity
(emphasis
added)
of
the
equipment,
however,
must
be
included
in
determining
the
total
storage
capacity
of
the
facility,
which
determines
whether
a
facility
is
subject
to
the
Oil
Pollution
Prevention
regulation."
56
FR
54623.
We
discuss
this
capacity
in
the
context
of
the
general
requirements
for
secondary
containment.
Thus,
it
is
clear
that
we
have
always
intended
235
capacity
to
be
the
determinative
factor
in
both
subjecting
a
facility
to
the
rule
and
in
determining
the
need
for
secondary
containment.

We
also
deleted
the
phrase
"but
they
may
not
always
be
appropriate"
from
the
third
sentence
of
the
paragraph
because
it
is
confusing
when
compared
to
the
text
of
§112.7(
d).
Under
§112.7(
d),
if
secondary
containment
is
not
practicable,
you
may
provide
a
contingency
plan
in
your
SPCC
Plan
and
otherwise
comply
with
that
section.
In
the
last
sentence,
"plant"
becomes
"facility."
Also
in
that
sentence,
the
phrase
"so
that
a
spill
could
terminate...."
becomes
"so
that
any
discharge
will
terminate...."

Electrical
or
other
operating
equipment.
Because
electrical,
operating,
manufacturing
equipment
are
not
bulk
storage
containers,
the
§112.8(
c)(
2)
secondary
containment
requirement
is
inapplicable
to
those
devices
or
equipment.
56
FR
54623.
However,
the
general
secondary
containment
requirement
at
§112.7(
c)
is
applicable.
If
it
is
not
practicable
from
a
matter
of
good
engineering
practice
(for
example,
because
of
safety
reasons
or
the
danger
of
fire
or
explosion)
to
install
secondary
containment
for
oil­
filled
equipment,
the
owner
or
operator
must
provide
a
contingency
plan
following
part
109
and
otherwise
comply
with
§112.7(
d).

Model
fire
codes.
Compliance
with
a
model
fire
code
may
be
acceptable
under
§112.8(
c)
if
the
code
meets
the
requirements
of
the
section.
We
note
that
we
meet
with
fire
code
officials
from
time
to
time.

Secondary
containment,
in
general.
A
primary
containment
system
is
the
container
or
equipment
in
which
oil
is
stored
or
used.
Secondary
containment
is
a
requirement
for
all
bulk
storage
facilities,
large
or
small,
manned
or
unmanned;
and
for
facilities
that
use
oil­
filled
equipment;
whenever
practicable.
Such
containment
must
at
least
provide
for
the
capacity
of
the
largest
single
tank
with
sufficient
freeboard
for
precipitation.
A
discharge
as
described
in
§112.
1(
b)
from
a
small
facility
may
be
as
environmentally
harmful
as
such
a
discharge
from
a
large
facility,
depending
on
the
surrounding
environment.
Likewise,
a
discharge
from
a
manned
facility
needs
to
be
contained
just
as
a
discharge
from
an
unmanned
one.
A
phase­
in
of
these
requirements
is
not
appropriate
because
secondary
containment
is
already
required
under
current
rules.
When
secondary
containment
is
not
practicable,
the
owner
or
operator
of
a
facility
may
deviate
from
the
requirement
under
§112.7(
d),
explain
the
rationale
in
the
Plan,
provide
a
contingency
plan
following
the
provisions
of
40
CFR
part
109,
and
otherwise
comply
with
§112.7(
d).

Because
a
pit
used
as
a
form
of
secondary
containment
may
pose
a
threat
to
birds
and
wildlife,
we
encourage
an
owner
or
operator
who
uses
a
pit
to
take
measures
to
mitigate
the
effect
of
the
pit
on
birds
and
wildlife.
Such
measures
may
include
netting,
fences,
or
other
means
to
keep
birds
or
animals
away.
In
some
cases,
pits
may
also
cause
a
discharge
as
described
in
§112.
1(
b).
The
discharge
may
occur
when
oil
spills
over
the
top
of
the
pit
or
when
oil
seeps
through
the
ground
into
groundwater,
and
thence
to
navigable
waters
or
adjoining
shorelines.
Therefore,
we
recommend
that
an
owner
or
operator
not
use
pits
in
an
area
where
such
pit
may
prove
a
source
of
such
discharges.
236
Should
the
oil
reach
navigable
waters
or
adjoining
shorelines,
it
is
a
reportable
discharge
under
40
CFR
110.6.

We
disagree
that
the
rule
is
duplicative
of
NPDES
rules.
Forseeable
or
chronic
point
source
discharges
that
are
permitted
under
CWA
section
402,
and
that
are
either
due
to
causes
associated
with
the
manufacturing
or
other
commercial
activities
in
which
the
discharger
is
engaged
or
due
to
the
operation
of
treatment
facilities
required
by
the
NPDES
permit,
are
to
be
regulated
under
the
NPDES
program.
"Classic
spill"
situations
are
subject
to
the
requirements
of
CWA
section
311.
Such
spills
are
governed
by
section
311
even
where
the
discharger
holds
a
valid
and
effective
NPDES
permit
under
section
402.
52
FR
10712,
10714.
Therefore,
the
typical
bulk
storage
facility
with
no
permitted
discharge
or
treatment
facility
would
not
be
under
the
NPDES
rules.

The
secondary
containment
requirements
of
the
rule
apply
to
bulk
storage
containers
and
their
purpose
is
to
help
prevent
discharges
as
described
in
§112.1(
b)
by
containing
discharged
oil.
NPDES
rules,
on
the
other
hand,
may
at
times
require
secondary
containment,
but
do
not
always.
Furthermore,
NPDES
rules
may
not
always
apply
to
bulk
storage
facilities.
Therefore,
the
rule
is
not
always
duplicative
of
NPDES
rules.
Where
it
is
duplicative,
an
owner
or
operator
of
a
facility
subject
to
NPDES
rules
may
use
that
portion
of
his
Best
Management
Practice
Plan
as
part
of
his
SPCC
Plan.

Alternatives.
Oil/
water
separators.
The
rule
does
not
mandate
the
use
of
any
specific
means
of
secondary
containment.
Any
system
that
achieves
the
purpose
of
the
rule
is
acceptable.
That
purpose
is
to
prevent
discharges
as
described
in
§112.1(
b).

Phase­
in.
There
is
no
need
for
a
phase­
in
of
secondary
containment
requirements
because
they
are
already
in
effect
and
apply
to
all
facilities,
large
and
small.

Snow
and
ice.
We
disagree
that
secondary
containment
is
unnecessary
for
facilities
in
which
drifting
snow
turns
to
ice
in
the
diked
area.
Such
snow
or
ice
may
be
contaminated
with
oil
and
cause
harm
to
the
environment
if
it
escapes
the
facility.

Seventy­
two­
hour
impermeability
standard.
As
noted
above,
we
have
decided
to
withdraw
the
proposal
for
the
72­
hour
impermeability
standard
and
retain
the
current
standard
that
diked
areas
must
be
sufficiently
impervious
to
contain
oil.
We
take
this
step
because
we
agree
with
commenters
that
the
purpose
of
secondary
containment
is
to
contain
oil
from
reaching
waters
of
the
United
States.
The
rationale
for
the
72­
hour
standard
was
to
allow
time
for
the
discovery
and
removal
of
an
oil
spill.
We
believe
that
an
owner
or
operator
of
a
facility
should
have
flexibility
in
how
to
prevent
discharges
as
described
in
§112.1(
b),
and
that
any
method
of
containment
that
achieves
that
end
is
sufficient.
Should
such
containment
fail,
an
owner
or
operator
must
immediately
clean
up
any
discharged
oil.
Similarly,
we
intend
that
the
purpose
of
the
"sufficiently
impervious"
standard
is
to
prevent
discharges
as
described
in
§112.1(
b)
by
ensuring
237
that
diked
areas
can
contain
oil
and
are
sufficiently
impervious
to
prevent
such
discharges.

"Should
to
shall"
cost.
There
is
no
cost
in
the
"should
to
shall
to
must"
change
because
the
change
is
merely
editorial.

Sufficient
freeboard.
An
essential
part
of
secondary
containment
is
sufficient
freeboard
to
contain
precipitation.
Whatever
method
you
use
to
calculate
the
amount
of
freeboard
that
is
"sufficient"
must
be
documented
in
the
Plan.
We
believe
that
the
proper
standard
of
"sufficient
freeboard"
to
contain
precipitation
is
that
amount
necessary
to
contain
precipitation
from
a
25­
year,
24­
hour
storm
event.
That
standard
allows
flexibility
for
varying
climatic
conditions.
It
is
also
the
standard
required
for
certain
tank
systems
storing
or
treating
hazardous
waste.
See,
for
example,
40
CFR
265.1(
e)(
1)(
ii)
and
(e)(
2)(
ii).
While
we
believe
that
25­
year,
24­
hour
storm
event
standard
is
appropriate
for
most
facilities
and
protective
of
the
environment,
we
are
not
making
it
a
rule
standard
because
of
the
difficulty
and
expense
for
some
facilities
of
securing
recent
information
concerning
such
storm
events
at
this
time.
Recent
data
does
not
exist
for
all
areas
of
the
United
States.
Furthermore,
available
data
may
be
costly
for
small
operators
to
secure.
Should
recent
and
inexpensive
information
concerning
a
25­
year,
24­
hour
storm
event
for
any
part
of
the
United
States
become
easily
accessible,
we
will
reconsider
proposing
such
a
standard.

XI
­
B(
3)
Drainage
of
rainwater
­
§112.8(
c)(
3)

Issues.
In
1991,
we
also
proposed
several
changes
to
§112.7(
e)(
2)
of
the
current
rule
on
bulk
storage
tanks
at
onshore
facilities
(excluding
production
facilities).
Specifically,
we
proposed
to
redesignated
§112.7(
e)(
2)(
iii)
as
§112.
8(
c)(
3).
Proposed
paragraph
(c)(
3)
addressed
drainage
from
diked
areas
around
bulk
storage
tank
installations.
It
contains
requirements
for
drainage
of
uncontaminated
rainwater
from
a
diked
area
into
a
storm
drain
or
discharge
of
an
effluent
into
an
open
watercourse,
lake,
or
pond,
bypassing
the
facility
treatment
system.

Comments:
NPDES.
Records
of
discharges
that
do
not
violate
water
quality
standards
are
unnecessary.
"It
is
more
logical
and
less
confusing
to
train
operators
to
report
by
exception."
(88)
"To
avoid
unnecessarily
duplicative
and
overlapping
work,
we
request
that
the
Agency
clarify
that
records
and
testing
normally
required
for
a
permitted
outfall
under
the
NPDES
program
are
adequate
to
fulfill
the
requirements
under
this
section."
(92)

Methods.
The
proposed
requirement
in
§112.8(
c)(
3)
to
close
and
seal
drains
on
dikes
or
equivalent
measures
at
all
times,
except
when
rainwater
is
being
drained,
precludes
engineering
measures,
such
as
standpipes,
based
on
good
engineering
practice.
Requiring
the
closing
of
standpipe
valves
defeats
the
purpose
of
installing
the
valves
in
the
first
place.
(28,
101,
165,
L15,
L27)
238
Response:
Methods.
Acceptable
measures
might,
depending
on
good
engineering
practice,
include
using
structures
such
as
standpipes
designed
to
handle
flow­
through
conditions
at
certain
oil
production
operations,
where
large
volumes
of
water
may
be
directed
to
oil
storage
tanks
if
water
discharge
lines
on
oil­
water
separators
become
plugged.

NPDES.
We
are
not
adopting
the
NPDES
rules
for
SPCC
purposes,
but
are
only
offering
an
alternative
for
recordkeeping.
The
intent
of
the
rule
is
that
you
may,
if
you
choose,
use
the
NPDES
stormwater
discharge
records
in
lieu
of
records
specifically
created
for
SPCC
purposes.
We
are
not
incorporating
the
NPDES
requirements
into
our
rules
by
reference.

This
paragraph
applies
to
discharges
of
rainwater
from
diked
areas
that
may
contain
any
type
of
oil,
including
animal
fats
and
vegetable
oils.
The
only
purpose
of
this
paragraph
is
to
offer
a
recordkeeping
option
so
that
you
do
not
have
to
create
a
duplicate
set
of
records
for
SPCC
purposes,
when
adequate
records
created
for
NPDES
purposes
already
exist.

XI
­
B(
4)
Completely
buried
tanks;
corrosion
protection
­
§112.8(
c)(
4)

Background:
In
1991,
we
redesignated
and
reproposed
current
§112.7(
e)(
2)(
iv)
as
§112.8(
c)(
4),
to
require
that
an
owner
or
operator
protect
new
completely
buried
storage
tanks
installed
on
or
after
January
10,
1974,
from
corrosion
by
coatings,
cathodic
protection,
or
other
effective
methods
compatible
with
local
soil
conditions.

In
1991,
we
also
proposed
changing
the
§112.7(
e)(
2)(
iv)
requirement
for
regular
pressure
testing
to
a
recommendation
for
regular
leak
testing
of
buried
tanks.
We
specified
leak
testing
rather
than
pressure
testing
to
be
consistent
with
many
State
rules.
Because
completely
buried
tanks
currently
subject
to
the
technical
requirements
of
40
CFR
parts
280
and
281,
the
underground
storage
tank
(UST)
regulations,
are
generally
exempted
from
SPCC
requirements
under
proposed
§112.1(
d)(
4),
§112.8(
c)(
4)
applies
only
to
tanks
not
subject
to
40
CFR
part
280
or
281.

Comments:
Part
280
standards.
We
should
avoid
duplicative
environmental
requirements
by
expressly
stating
that
metallic
USTs
must
meet
the
"appropriate
requirements
of
40
CFR
280."
(44,
67,
85,
111,
175,
180)

Corrosion
protection.

Support
for
proposal.
"We
support
the
proposed
requirement
for
protective
coating
and
cathodic
protection
for
new
or
replaced
buried
piping,
regardless
of
soil
conditions."
(L17)

Opposition
to
proposal.

"Unenforceable."
Proposal
"is
unenforceable."
(121)
239
Monitoring
effectiveness.
"...(
T)
he
regulation
contains
no
discussion
of
cathodic
protection
for
tank
bottoms
in
contact
with
soil
or
fill
materials.
Also
the
regulation
includes
no
requirements
for
monitoring
the
effectiveness
of
cathodic
protection
of
buried
tanks
and
piping."
(16)

Leak
testing.

Support
for
proposal.
Support
for
our
proposal
for
discretionary
leak
(or
discharge)
testing
with
some
modifications.
(48,
67,
85,
102)
"ILMA
agrees
that
making
this
a
recommended,
rather
than
mandatory,
practice
is
consistent
with
the
goal
of
using
good
engineering
practice.
This
offers
regulated
facilities
the
flexibility
to
monitor
these
tanks
with
a
frequency
necessitated
by
site­
specific
circumstances,
such
as
the
ages
of
the
tanks
or
soil
conditions."
(48)

Opposition
to
proposal.
"As
to
leak
testing,
there
is
no
current
requirement
for
integrity
testing
of
buried
piping
at
storage
facilities.
At
very
large
facilities
it
may
be
practical
to
conduct
the
type
of
testing
proposed.
However,
for
small
and
medium
facilities
it
is
impractical
and
would
be
extremely
costly
to
implement
this
recommended
practice."
(34)

Response:
Corrosion
protection.
We
agree
in
principle
that
all
completely
buried
tanks
should
have
some
type
of
corrosion
protection,
but
as
proposed,
we
will
only
extend
that
requirement
to
new
completely
buried
metallic
storage
tanks.
Because
corrosion
protection
is
a
feature
of
the
current
rule
(see
§112.7(
e)(
2)(
iv)),
the
requirement
applies
to
completely
buried
metallic
tanks
installed
on
or
after
January
10,
1974.
The
requirement
is
enforceable
because
it
is
a
procedure
or
method
to
prevent
the
discharge
of
oil.
See
section
311(
j)(
1)(
C)
of
the
CWA.
Most
owners
or
operators
of
completely
buried
storage
tanks
will
be
exempted
from
part
112
under
this
rule
because
such
tanks
are
subject
to
all
of
the
technical
requirements
of
40
CFR
part
280
or
a
State
program
approved
under
40
CFR
281.
Those
tanks
subject
to
40
CFR
part
280
or
a
State
program
approved
under
40
CFR
part
281
will
follow
the
corrosion
protection
provisions
of
that
rule,
which
provides
comparable
environmental
protection.
Those
that
remain
subject
to
the
SPCC
regulation
must
comply
with
this
paragraph.

The
rule
requires
corrosion
protection
for
completely
buried
metallic
tanks
by
a
method
compatible
with
local
soil
conditions.
Local
soil
conditions
might
include
fill
material.
The
method
of
such
corrosion
protection
is
a
question
of
good
engineering
practice
which
will
vary
from
facility
to
facility.
You
should
monitor
such
corrosion
protection
for
effectiveness,
in
order
to
be
sure
that
the
method
of
protection
you
choose
remains
protective.
See
§112.8(
d)(
1)
for
a
discussion
of
corrosion
protection
for
buried
piping.

UST
standards.
UST
or
other
industry
standards
may
satisfy
SPCC
requirements.

Leak
testing.
The
current
SPCC
rule
contains
a
provision
calling
for
the
"regular
pressure
testing"
of
buried
metallic
storage
tanks.
40
CFR
112.
7(
e)(
2)(
iv).
We
240
proposed
in
1991
a
recommendation
that
such
buried
tanks
be
subject
to
regular
"leak
testing."
Proposed
§112.8(
c)(
4).
Leak
testing
for
purposes
of
this
paragraph
is
testing
to
ensure
liquid
tightness
of
container
and
whether
it
may
discharge
oil.
We
specified
leak
testing
in
the
proposal,
instead
of
pressure
testing,
in
order
to
be
consistent
with
many
State
regulations
and
because
the
technology
on
such
testing
was
rapidly
evolving.
56
FR
at
54623.

We
are
modifying
the
leak
testing
recommendation
to
make
it
a
requirement.
We
agree
with
the
commenter
who
argued
that
such
testing
should
be
mandatory
because
recommendations
may
not
often
be
followed.
Appropriate
methods
of
testing
should
be
selected
based
on
good
engineering
practice.
Whatever
method
and
schedule
for
testing
the
PE
selects
must
be
described
in
the
Plan.
Testing
under
the
standards
set
out
in
40
CFR
part
280
or
a
State
program
approved
under
40
CFR
part
281
is
certainly
acceptable
(as
we
suggested
in
the
proposed
rule).
"Regular
testing"
means
testing
in
accordance
with
industry
standards
or
at
a
frequency
sufficient
to
prevent
leaks.

XI
­
B(
5)
Partially
buried
or
bunkered
tanks
­
§112.8(
c)(
5)

Background:
Under
§112.7(
e)(
2)(
v)
of
the
current
rule,
a
partially
buried
metallic
tank
must
be
avoided
unless
the
shell
is
coated,
since
damp
earth
can
cause
rapid
corrosion
of
a
buried
tank,
especially
where
air
and
soil
contact.
In
1991,
we
proposed
in
§112.8(
c)(
5)
to
recommend
against
storing
oil
in
partially
buried
or
bunkered
metallic
tanks.
However,
if
such
tanks
are
used,
we
proposed
to
require
that
the
owner
or
operator
protect
the
buried
or
bunkered
metallic
tank
from
corrosion
by
using
coatings,
cathodic
protection,
or
other
methods
compatible
with
local
soil
conditions.

Comments:
Applicability.
We
should
clarify
that
the
proposed
recommendation
applies
only
to
new
partially
buried
tanks.
(54)

Editorial
suggestion.
We
could
omit
§112.8(
c)(
5)
by
removing
the
term
"partially
buried
tanks."
(180)

Requirement
v.
recommendation.
Recommends
that
we
delete
the
first
sentence
of
§112.8(
c)(
5)
because
it
is
purely
advisory.
(121)

Response:
Applicability.
The
requirement
to
avoid
the
use
of
such
tanks,
unless
they
are
protected
from
corrosion,
applies
to
all
partially
buried
metallic
tanks,
installed
at
any
time.
This
requirement
is
in
the
current
rule
and
applies
to
tanks
installed
since
the
effective
date
of
the
rule
in
1974.

Editorial
suggestion.
We
disagree
that
we
should
remove
the
term
"partially
buried
tanks"
or
delete
§112.8(
c)(
5).
Such
a
deletion
would
remove
partially
buried
tanks
from
the
corrosion
protection
requirements
of
the
rule.

Requirement
v.
recommendation.
Due
to
the
risk
of
discharge
caused
by
corrosion,
we
decided
to
keep
the
current
requirement
to
not
use
partially
buried
metallic
tanks,
unless
241
the
buried
section
of
such
tanks
are
protected
from
corrosion.
The
requirement
to
not
use
such
tanks,
unless
they
are
protected
from
corrosion,
applies
to
all
partially
buried
metallic
tanks,
installed
at
any
time.

XI
­
B(
6)
Integrity
testing
­
§112.8(
c)(
6)

Background:
Current
§112.7(
e)(
2)(
vi)
requires
an
owner
or
operator
to
conduct
periodic
integrity
testing
of
aboveground
bulk
storage
tanks,
taking
into
account
tank
design
and
using
such
techniques
as
hydrostatic
testing,
visual
inspection,
or
a
system
of
non­
destructive
shell
thickness
testing.
In
1991,
we
proposed
to
redesignated
§112.7(
e)(
2)(
vi)
as
§112.8(
c)(
6),
and
to
require
that
an
owner
or
operator
of
a
facility
with
adequate
secondary
containment
conduct
integrity
testing
of
aboveground
bulk
storage
tanks
every
ten
years
and
when
there
are
material
repairs
to
an
aboveground
tank.
We
also
proposed
to
maintain
the
current
requirement
for
keeping
comparison
records
and
for
inspecting
the
tank's
supports
and
foundations.
Further,
we
proposed
to
maintain
the
current
requirement
for
operating
personnel
to
observe
the
outside
of
the
tank
frequently
for
signs
of
deterioration,
leaks,
or
oil
accumulation
inside
diked
areas.

Comments:
Support
for
proposal.
"Ashland
supports
the
agency's
proposal
to
require
integrity
testing
of
bulk
storage
tanks
once
every
ten
years
and
when
material
repairs
are
performed."
(83,
102,
L35)

Opposition
to
proposal.

Air
emissions,
fatalities.
The
release
of
gas
from
testing
would
increase
air
emissions
and
the
risk
of
fatalities.
Tanks
"in
severe
environments
or
service"
may
not
have
a
ten­
year
life
expectancy.
(67)
.
Cost,
out­
of­
service
tanks.
Owners
or
operators
would
have
to
build
replacement
tanks
for
the
10
percent
of
tanks
taken
out­
of­
service
every
year
for
testing.
(67)

Logistically
difficult.
Internally
inspecting
tanks
is
costly
and
logistically
difficult.
(L35)

Environmental
threat.
Integrity
testing
is
unwarranted
since
many
tanks
are
inspected
daily,
and
tanks
located
inside
buildings
are
less
likely
to
pose
an
environmental
threat
than
outside
tanks.
(71)
The
ten­
year
testing
requirement
is
costly
and
may
not
have
an
environmental
benefit,
since
secondary
containment
contains
the
tank's
contents
if
there
is
a
failure.
(90)

Residual
oil.
"A
ten­
year
testing
cycle
is
simply
not
justified
for
residual
oil
tanks.
Such
relatively
frequent
forced
outages
will
likely
impact
system
reliability
in
the
context
of
maintaining
reserve
capacity
requirements
if,
for
example,
a
particular
generating
unit
is
supplied
from
a
specific
fuel
oil
tank
or
an
alternative
fuel
is
unavailable.
And
perhaps
more
important,
the
compensating
mechanism
for
avoiding
station
outages,
i.
e.,
to
barge
or
truck­
in
fuel
in
lieu
of
tank
supplies,
is
242
far
more
environmentally
threatening.
Consequently,
Con
Edison
recommends
that
residual
oil
tanks
be
excluded
from
the
testing
frequency
proposed
in
the
revised
section
112.8(
c)(
6)
or
alternatively,
that
the
testing
of
these
tanks
be
tied
to
practical
operational
factors
such
as
scheduled
maintenance
outages."
(100,
L35)

Unnecessary,
hazardous
waste.
Integrity
testing
is
unnecessary
because
"tanks
that
store
oil
have
a
lower
rust
potential"
(71)
and
"cleaning
would
generate
more
hazardous
waste"
(67).

Applicability.

Airport
fuel
systems.
"This
recommendation
does
not
mention
airport
fuel
hydrant
systems
associated
with
above
ground
fuel
storage
facilities
...."
(107)

Electrical
equipment.
Tank
integrity
testing
requirement
for
electric
equipment
containing
oil
is
burdensome
and
has
no
environmental
benefit.
Owners
or
operators
would
have
to
test
such
equipment
while
it
was
out­
of­
service,
which
is
impractical.
(92)
"While
the
electric
utilities
generally
believe
that
this
is
a
reasonable
proposal,
we
believe
that
two
exclusions
should
be
provided.
First,
...,
an
exclusion
should
be
provided
for
tanks
used
to
store
oils
with
a
pour
point
greater
than
60
degrees
Fahrenheit.
Such
tanks
pose
little
risk
to
navigable
waters
because
the
oil
does
not
flow
freely.
...
A
second
exclusion
should
be
provided
for
tanks
that
are
capable
of
visible
inspection
on
all
sides
and
utilize
secondary
containment."
(92,
125,
L2)

Phase­
in.

10
years.
Suggests
testing
be
phased
in
over
the
"next
ten
years
after
enactment
of
the
final
rule."
(92,
125)

UST
model.
"There
should
be
a
phase­
in
period
for
testing
of
aboveground
tanks
subject
to
112.8(
c)(
6).
This
could
be
based
on
age
of
the
tank
and
modeled
after
the
UST
program
requirements
for
phase­
in
of
leak
detection."
(161)

Small
facilities.
We
should
differentiate
between
large
and
small
facilities
because
the
ten­
year
testing
requirement
is
inappropriate
for
small
tanks
at
small
facilities.
(34)
"GM
also
believes
that
mandatory
testing
of
aboveground
tanks
every
ten
years
at
a
minimum,
is
unnecessary
for
small
volume
tanks
and
at
facilities
that
have
incorporated
secondary
containment
structures."
(90)
We
should
consider
exempting
tanks
based
on
size
and
tanks
with
100
percent
containment.
(191)

Suggested
threshold
levels.
243
Less
than
2,000
gallons.
We
should
exempt
from
the
testing
requirement,
tanks
contained
within
a
building
or
with
a
maximum
capacity
of
less
than
2,000
gallons,
tanks
with
all
sides
visible,
and
tanks
and
any
associated
piping
and
ancillary
equipment
that
are
visually
inspected
monthly.
(71)

10,000
gallons
or
more.
We
should
require
an
owner
or
operator
to
inspect
aboveground
tanks
with
a
capacity
of
10,000
gallons
or
more
internally
for
structural
soundness,
tank
bottom
corrosion,
and
wall
thinning.
An
owner
or
operator
could
conduct
hydrostatic
testing
between
ten
year
intervals,
but
not
as
a
substitute
for
a
thorough
inspection.
(111)

Type
of
oil
stored.
"The
proposed
amendment
does
not
properly
reflect
the
difference
between
groundwater
and
surface
water
impact
potential
of
different
petroleum
products
such
as
gasoline,
#
2
fuel
oil
or
#
6
fuel
oil
nor
do
the
proposed
changes
differentiate
or
give
consideration
to
petroleum
storage
facilities
over
groundwater
deep
recharge
areas
as
opposed
to
those
in
less
sensitive
hydrogeologic
zones."
(100,
L35)

Heavy
oils.
Re
#5
and
#6
fueloiltanks:"
It
is
very
expensive
and
timeconsuming
to
perform
integrity
tests
on
such
tanks
and
because
of
the
viscosity
and
pour
point
of
these
products,
there
is
little
likelihood
that
these
products
could
flow
and
cause
any
substantial
environmental
damage."
(54,
L35)
"In
New
York
State,
for
example,
the
bulk
storage
regulations
effectively
exclude
No.
6
fuel
oil
and
other
petroleum
products
for
purposes
of
regulatory
control."
(100)
"First,
...,
an
exclusion
should
be
provided
for
tanks
used
to
store
oils
with
a
pour
point
greater
than
60
degrees
Fahrenheit.
Such
tanks
pose
little
risk
to
navigable
waters
because
the
oil
does
not
flow
freely.
Moreover,
the
costs
of
cleaning
and
testing
such
tanks
is
extremely
high
because
of
the
difficulty
of
removing
oil
from
the
tank."
(125)

Residual
oil.
"A
ten­
year
testing
cycle
is
simply
not
justified
for
residual
oil
tanks.
Such
relatively
frequent
forced
outages
will
likely
impact
system
reliability
in
the
context
of
maintaining
reserve
capacity
requirements
if,
for
example,
a
particular
generating
unit
is
supplied
from
a
specific
fuel
oil
tank
or
an
alternative
fuel
is
unavailable."
(100)

Clarification.
"`
Integrity
testing'
is
not
defined."
(70)

Frequency
of
testing.

Construction
material
or
usage.
"The
requirement
of
testing
every
ten
years
does
not
take
into
account
construction
materials,
usage,
or
many
other
factors.
It
is
suggested
that
more
flexibility
is
warranted
to
address
particular
cases."
(L30)

Industry
standards.
"Also,
the
integrity
test
interval
of
10
years
for
tanks
with
containment
seems
to
conflict
with
API
guidance
recommending
ultrasound
thickness
measurements
within
5
years
after
commissioning
new
tanks
and
at
5
244
year
intervals
for
existing
tanks
where
the
corrosion
rate
is
not
know."
(16)
"API
suggests
that
adherence
to
accepted
industry
operating
and
inspection
standards
should
also
e
accepted
in
place
of
the
proposed
10
year
integrity
testing
interval.
In
some
cases
industry
standards
provide
more
specificity,
and
in
others,
more
stringent
requirements
that
the
proposed
wording."
(67)

More
frequent.
The
proposed
rule
"contains
too
long
a
period
between
AST
integrity
tests
(10
years).
EPA
should
develop
an
AST
integrity
testing
schedule
that
provides
for
more
frequent
testing
for
older
tanks
with
bottoms
made
of
corrosive
material."
(44,
88)

More
limited.
We
should
limit
the
required
integrity
testing
frequency.
(71)

Material
repairs.
"However,
to
help
clarify
what
constitute
material
repairs,
§112.8(
c)(
6)
should
be
revised
to
indicate
that
such
testing
must
be
performed
when
the
repairs
involve
the
installation
of
a
12
inch
or
larger
nozzle
in
the
shell,
a
new
steel
bottom,
a
door
sheet,
tombstone
replacement
in
the
shell,
or
other
similar
repairs
that
could
materially
increase
the
potential
for
oil
to
be
discharged
from
the
tank."
(83,
102)

Method
of
testing.

Other
techniques.
Between
hydrostatic
testing,
we
should
allow
owners
or
operators
to
use
other
inspection
techniques
while
the
tanks
are
in
service.
This
approach
would
permit
owners
or
operators
to
schedule
tank
outages
while
supporting
supply
and
demand
obligations.
(25)

Rule
list.
"Guidelines
or
recommendations
for
inspections
and
testing
procedures
should
be
set
forth
here."
(27)
"Unless
you
are
prepared
to
state
what
type
of
`integrity
testing'
is
acceptable
to
EPA,
and
to
what
standards,
this
paragraph
should
be
deleted."
(121)

Visual
inspection.

Internal
and
external.
"The
seriousness
of
certain
conditions
such
as
tank
bottom
settlement,
bottom
corrosion,
or
poor
condition
of
roof
supports
may
not
be
identified
by
this
type
of
`integrity
testing'.
EPA
should
consider
requiring
that
integrity
testing
procedures
be
complemented
with
a
formal
internal
visual
inspection
when
the
tank
is
not
in
service."
(16)
"It
should
be
clarified
if
the
extent
of
a
visual
inspection
would
be
expected
to
be
both
inside
and
out
(that
is,
product
and
vapors
removed)."
(76)

Visual
inspections
adequate.
"We
support
the
need
to
review
the
integrity
of
tanks.
We
are
not
in
favor
of
pressure
testing
and
would
be
concerned
with
the
amount
of
pressure
applied.
...
Visual
inspection
is
much
more
economical
and
will
be
used
as
often
as
twice
yearly
where
possible.
Remote
sites
would
be
inspected
at
least
yearly,
with
full
time
electronic
monitoring
used
when
possible."
245
(37)
"A
second
exclusion
should
be
provided
for
tanks
that
are
capable
of
visible
inspection
on
all
sides
and
utilize
secondary
containment.
In
such
a
case,
where
the
tank
bottom
as
well
as
the
sides
can
be
adequately
inspected,
integrity
testing
is
not
necessary
to
maintain
the
safety
of
the
tanks."
(125)
"The
Company
feels
that
visually
inspecting
aboveground
tanks
fully
meets
the
intent
of
the
testing
requirement.
During
the
aforementioned
UST
rulemaking
in
1988,
EPA
totally
exempted
USTs
which
were
in
basements
or
vaults
if
the
USTs
were
totally
inspectable
for
leaks.
EPA
recognized
that
these
tanks,
although
they
were
subterranean,
did
not
require
upgrading,
release
detection,
etc.,
based
upon
the
simple
fact
that
they
were
inspectable
and
this
was
a
reliable
means
of
detecting
leakage."
(164)

Response:
Support
for
proposal.
We
appreciate
commenter
support.

Applicability.
Integrity
testing
is
essential
for
all
aboveground
containers
to
help
prevent
discharges.
Testing
will
show
whether
corrosion
has
reached
a
point
where
repairs
or
replacement
of
the
container
is
needed.
Prevention
of
discharges
is
preferable
to
cleaning
them
up
afterwards.
Therefore,
it
must
apply
to
large
and
small
containers,
containers
on
and
off
the
ground
wherever
located,
and
to
containers
storing
any
type
of
oil.
From
all
of
these
containers
there
exists
the
possibility
of
discharge.

Air
emissions,
fatalities.
An
owner
or
operator
who
follows
good
engineering
practice
will
minimize
the
possibility
of
air
emissions
or
fatalities.
In
any
event,
an
owner
or
operator
must
comply
with
applicable
State
and
Federal
clean
air
and
safety
requirements.

Ancillary
equipment.
We
agree
that
integrity
testing
should
include
ancillary
equipment
in
some
circumstances,
and
require
integrity
and
leak
testing
on
a
periodic
basis
for
valves
and
piping
when
a
facility
lacks
secondary
containment.
40
CFR
112.7(
d).
Even
with
secondary
containment,
an
owner
or
operator
must
examine
all
aboveground
valves,
piping,
and
appurtenances
regularly
to
assess
the
general
condition
of
certain
items.
40
CFR
112.8(
d)(
4).
In
addition,
an
owner
or
operator
must
conduct
integrity
and
leak
testing
of
buried
piping
at
the
time
of
installation,
modification,
construction,
relocation,
or
replacement.
40
CFR
112.8(
d)(
4)

Electrical
equipment.
Because
electrical,
operating,
manufacturing
equipment
are
not
bulk
storage
containers,
the
requirement
is
inapplicable
to
those
devices
or
equipment.
56
FR
54623.
See
also
the
definition
of
bulk
storage
container
in
§112.2.
Furthermore,
as
noted
by
commenters,
methods
may
not
exist
for
integrity
testing
of
such
devices
or
equipment.

Hazardous
waste.
While
it
is
possible
that
cleaning
might
generate
more
hazardous
waste,
that
is
not
a
reason
to
avoid
integrity
testing.
The
purpose
of
the
testing
is
to
prevent
container
failure
leading
to
a
discharge
as
described
in
§112.1(
b).
246
Phase­
in.
We
disagree
that
there
should
be
a
phase­
in
of
the
requirement
because
it
is
already
in
effect.

Rust.
A
container
with
any
potential
to
rust
may
fail
and
discharge
oil.
Further,
rust
is
not
the
only
possible
failure
factor.
For
example,
integrity
testing
may
reveal
an
improper
weld
or
inadequate
shell
thickness
before
the
defect
causes
a
container
to
fail.

Secondary
containment.
We
disagree
that
secondary
containment
for
the
entire
content
of
a
container
mitigates
the
need
for
integrity
testing.
Such
testing
helps
prevent
the
discharge
in
the
first
place.
Furthermore,
oil
may
escape
secondary
containment
and
reach
the
environment.

Business
records.
You
may
use
usual
and
customary
business
records,
at
your
option,
for
purposes
of
integrity
testing
recordkeeping.
Specifically,
you
may
use
records
maintained
under
API
Standards
653
and
2610
for
purposes
of
this
section,
if
you
choose.
Other
usual
and
customary
business
records
either
existing
or
to
be
developed
in
the
future
may
also
suffice.
Or,
you
may
elect
to
keep
separate
records
for
SPCC
purposes.
This
section
requires
you
to
keep
comparison
records.
Section
112.7(
e)
requires
retention
of
these
records
for
three
years.
You
should
note,
however,
that
certain
industry
standards
(for
example,
API
Standards
570
and
653)
may
specify
that
an
owner
or
operator
to
maintain
records
for
longer
than
three
years.

Frequency
of
testing,
industry
standards,
10­
year
integrity
testing.
Integrity
testing
is
a
necessary
component
of
any
good
prevention
plan.
A
number
of
commenters
supported
a
requirement
for
such
testing.
It
will
help
to
prevent
discharges
by
testing
the
strength
and
imperviousness
of
the
container.
We
agree
with
commenters
that
testing
according
to
industry
standards
is
preferable,
and
thus
will
maintain
the
current
standard
of
regularly
scheduled
testing
instead
of
prescribing
a
particular
period
for
testing.
Industry
standards
may
at
times
be
more
specific
and
more
stringent
than
our
proposed
rule.
For
example,
API
Standard
653
provides
specific
criteria
for
internal
inspection
frequencies
based
on
the
calculated
corrosion
rate,
rather
than
an
arbitrary
time
period.
API
Standard
653
allows
the
aboveground
storage
tank
(AST)
owner
or
operator
the
flexibility
to
implement
a
number
of
options
to
identify
and
prevent
problems
which
ultimately
lead
to
a
loss
of
tank
integrity.
It
establishes
a
minimum
and
maximum
interval
between
internal
inspections.
It
requires
an
internal
AST
inspection
when
the
estimated
corrosion
rate
indicates
the
bottom
will
have
corroded
to
0.1
inches.
Certain
prevention
measures
taken
to
prevent
a
discharge
from
the
tank
bottom
may
affect
this
action
level
(thickness).
Once
this
point
has
been
reached,
the
owner
or
operator
has
to
make
a
decision,
depending
on
the
future
service
and
operating
environment
of
the
tank,
to
either
replace
the
whole
tank,
line
the
bottom,
add
cathodic
protection,
replace
the
tank
bottom
with
a
new
bottom,
add
a
release
prevention
barrier,
or
some
combination
of
the
above.

Another
benefit
from
the
use
of
industry
standards
is
that
they
specify
when
and
where
specific
tests
may
and
may
not
be
used.
For
example,
API
Standard
653
is
very
specific
247
as
to
when
radiographic
tests
may
be
used
and
when
a
full
hydrostatic
test
is
required
after
shell
repairs.
Depending
on
shell
material
toughness
and
thickness
a
full
hydrotest
is
required
for
certain
shell
repairs.
Allowing
a
visual
inspection
in
these
cases
risks
a
tank
failure
similar
to
the
1988
Floreffe,
Pennsylvania
event.
Testing
on
a
"regular
schedule"
means
testing
per
industry
standards
or
at
a
frequency
sufficient
to
prevent
discharges.
Whatever
schedule
the
PE
selects
must
be
documented
in
the
Plan.

Integrity
testing.
"Integrity
testing"
is
any
means
to
measure
the
strength
(structural
soundness)
of
the
container
shell,
bottom,
and/
or
floor
to
contain
oil
and
may
include
leak
testing
to
determine
whether
the
container
will
discharge
oil.
It
includes,
but
is
not
limited
to,
testing
foundations
and
supports
of
containers.
Its
scope
includes
both
the
inside
and
outside
of
the
container.
It
also
includes
frequent
observation
of
the
outside
of
the
container
for
signs
of
deterioration,
leaks,
or
accumulation
of
oil
inside
diked
areas.

Material
repairs.
The
rationale
for
testing
at
the
time
material
repairs
are
conducted
is
that
such
repairs
could
materially
increase
the
potential
for
oil
to
be
discharged
from
the
tank.
Examples
of
such
repairs
include
removing
or
replacing
the
annular
plate
ring;
replacement
of
the
container
bottom;
jacking
of
a
container
shell;
installation
of
a
12­
inch
or
larger
nozzle
in
the
shell;
a
door
sheet,
tombstone
replacement
in
the
shell,
or
other
shell
repair;
or,
such
repairs
that
might
materially
change
the
potential
for
oil
to
be
discharged
from
the
container.

Method
of
testing.
The
rule
requires
visual
testing
in
conjunction
with
another
method
of
testing,
because
visual
testing
alone
is
normally
insufficient
to
measure
the
integrity
of
a
container.
Visual
testing
alone
might
not
detect
problems
which
could
lead
to
container
failure.
For
example,
studies
of
the
1988
Ashland
oil
spill
suggest
that
the
tank
collapse
resulted
from
a
brittle
fracture
in
the
shell
of
the
tank.
Adequate
fracture
toughness
of
the
base
metal
of
existing
tanks
is
an
important
consideration
in
discharge
prevention,
especially
in
cold
weather.
Although
no
definitive
non­
destructive
test
exists
for
testing
fracture
toughness,
had
the
tank
been
evaluated
for
brittle
fracture,
for
example
under
API
standard
653,
and
had
the
evaluation
shown
that
the
tank
was
at
risk
for
brittle
fracture,
the
owner
or
operator
could
have
taken
measures
to
repair
or
modify
the
tank's
operation
to
prevent
failure.

List
of
procedures.
We
disagree
that
we
should
state
in
the
rule
­­
not
the
preamble
­­
what
integrity
testing
procedures
we
consider
adequate.
We
list
examples
in
the
rule
of
possible
types
of
testing,
but
those
are
merely
examples.
While
we
suggest
testing
according
to
industry
standards,
we
realize
those
standards
will
not
be
appropriate
for
every
facility.
Where
industry
standards
are
inappropriate
for
a
particular
facility,
the
Professional
Engineer
must
devise
a
standard
of
testing
that
is
appropriate.
We
note,
however,
that
a
visual
inspection
must
be
combined
with
some
other
technique.

Pressure
testing.
We
note
that
we
do
not
require
pressure
testing.
248
Routine
inspections.
We
disagree
that
a
routine
inspection
suffices
for
an
integrity
test.
A
routine
inspection
may
be
visual
and
may
not
test
the
tank
sufficiently
to
meet
the
§112.8(
c)(
6)
integrity
testing
requirement.
We
also
disagree
that
we
should
require
integrity
testing
only
when
the
inspector
thinks
there
is
a
risk
of
discharge
because
such
a
standard
is
entirely
subjective.

Visual
inspection.
For
certain
smaller
shop­
built
containers
in
which
internal
corrosion
poses
minimal
risk
of
failure;
which
are
inspected
at
least
monthly;
and,
for
which
all
sides
are
visible
(i.
e.,
the
container
has
no
contact
with
the
ground),
visual
inspection
alone
might
suffice,
subject
to
good
engineering
practice.
In
such
case
the
owner
or
operator
must
explain
in
the
Plan
why
visual
integrity
testing
alone
is
sufficient,
and
provide
equivalent
environmental
protection.
40
CFR
112.7(
a)(
2).
However,
containers
which
are
in
contact
with
the
ground
must
be
evaluated
for
integrity
in
accordance
with
industry
standards
and
good
engineering
practice.

Internal
and
external.
A
visual
inspection
may
be
either
solely
external,
or
external
and
internal.
The
rule
requires
visual
testing
in
conjunction
with
another
method
of
testing,
because
visual
testing
alone
is
normally
insufficient
to
measure
the
integrity
of
a
container.
Visual
testing
alone
might
not
detect
problems
which
could
lead
to
container
failure.

XI
­
B(
7)
Leakage
­
internal
heating
coils
­
§112.8(
c)(
7)

Background:
In
1991,
we
proposed
to
redesignate
§112.7(
e)(
2)(
vii)
of
the
current
rule
as
§112.8(
c)(
7).
The
proposal
would
require
the
prevention
of
leakage
through
defective
internal
heating
coils.
In
1991,
we
also
proposed
a
new
recommendation
that
the
retention
systems
be
designed
to
hold
the
contents
of
an
entire
tank,
be
of
sufficient
size
to
contain
a
spill
that
may
occur
when
the
system
is
not
being
monitored
or
observed,
or
have
fail­
safe
oil
leakage
detectors.

Comments:
External
heating
system
recommendation.
"It
would
seem
that
the
cost
to
install
insulation,
upgrade
boilers,
and
pay
for
the
extra
energy
consumption
would
be
outlandish."
(76)

Internal
heating
coils,
opposition
to
recommendation.
"It
is
felt
that
aboveground
piping
can
be
easily
inspected
and
maintained;
and,
with
drainage
at
facilities
routed
to
oily
water
separators
or
holding
ponds,
it
is
unnecessary
to
have
leak
proof
galleys
under
aboveground
piping.
This
would
be
redundant
containment
and
encouraging
this
installation
is
economically
unjustified."
(25)
"The
recommendation
that
aboveground
piping
be
placed
into
galleys
that
drain
into
the
oil/
water
separator
is
not
necessary.
Leaks
in
the
aboveground
piping
can
be
mitigated
through
daily
inspections
and
they
are
often
placed
within
the
secondary
containment."
(68)
Instead
of
requiring
a
retention
system,
which
would
hold
the
entire
contents
of
a
tank,
suggests,
"A
reasonable
alternative
would
the
installation
of
an
oil/
water
separator
with
a
high
product
level
indicator;
or
a
flow­
stop
valve
which
incorporates
a
valve
that
closes
if
a
249
liquid
with
a
specific
gravity
of
less
than
1
is
present
(such
as
provided
by
Enquip
of
Tulsa)."
(76)

Oil/
water
separators.
"In
addition,
not
all
facilities
have
oil/
water
separators
and
the
same
ought
not
to
be
a
requirement.
...
The
choice
of
what
type
of
equipment
and
requirements
an
operating
facility
need
should
be
left
to
the
regulated
unit
and
the
qualified
independent
professional
engineer."
(162)

Response:
Alternatives.
The
rule
does
not
mandate
the
use
of
any
specific
separation
or
retention
system.
Any
system
that
achieves
the
purpose
of
the
rule
is
acceptable.
That
purpose
is
to
prevent
discharges
as
described
in
§112.
1(
b)
by
controlling
leakage.

Proposed
recommendation.
We
deleted
the
proposed
recommendation
from
the
rule
because
we
do
not
wish
to
confuse
the
regulated
public
as
to
what
is
mandatory
and
what
is
discretionary.
We
have
included
only
requirements
in
the
rule.

XI
­
B(
8)
Good
engineering
practice
­
alarm
systems
­
§112.8(
c)(
8)

Background:
In
1991,
we
proposed
to
redesignate
§112.7(
e)(
2)(
viii)
of
the
current
rule
as
§112.8(
c)(
8).
The
provision
pertains
to
engineering
requirements
formerly
labeled
"fail­
safe."

Comments:
Support
for
proposal.
Supports
proposed
list
of
devices
that
we
consider
to
be
"fail­
safe"
engineering.
(143)

Terminology.
Objects
to
the
term
"fail­
safe"
engineering
because
nothing
is
ever
failsafe
Suggests
using
term
"in
accordance
with
good
engineering
practice"
or
"consistent
with
accepted
industry
practices"
instead.
(54,
92)

Applicability.
"GM
recommends
that
installation
of
fail­
safe
equipment
be
required
for
storage
tanks
of
volume
greater
than
100,000
gallons,
and/
or
for
storage
tanks
that
were
the
cause
of
a
reportable
spill
within
the
past
three
years."
(90)
"If
fail
safe
devices
are
appropriate
for
specific
large
tanks,
the
requirement
should
be
phased
in
over
a
period
of
2
to
5
years."
(116)

Alternatives.

Procedures.
Supports
use
of
"procedures"
as
well
as
"devices"
as
good
engineering
practice
measures.
(54)
Tanks
filled
"with
an
operator
present
should
not
require
such
devices."
(116)

UST
rules.
"With
respect
to
overfill
requirements,
existing
Underground
Storage
Tank
(UST)
regulations
...
merely
require
a
five
(5)
gallon
overfill
bucket
­
a
standard
feature
for
vaulted
tanks.
Overfill
requirements,
as
contemplated
by
the
proposed
revised
regulations,
should
not
exceed
the
EPA
standards
for
USTs."
(50)
250
Monitoring.
"...
the
`fast
response
system'
for
overfill
prevention
does
not
provide
the
same
level
of
protection
as
a
high
level
alarm
or
high
liquid
level
pump
cutoff.
If
this
alternative
is
to
be
considered
further
by
EPA,
the
regulations
should
require
that
a
person
be
present
to
monitor
gauges
and
the
overall
filling
of
storage
tanks."
(111)

Response:
Support
for
proposal.
We
appreciate
commenter
support.

Terminology.
We
agree
with
the
commenter
that
"fail­
safe"
engineering
is
inappropriate
and
have
substituted
"in
accordance
with
good
engineering
practice."
The
change
in
terminology
does
not
imply
any
substantive
change
in
the
level
of
environmental
protection
required,
it
is
merely
editorial.

Applicability.
Alarm
system
devices
are
necessary
for
all
facilities,
large
or
small,
to
prevent
discharges.
Such
systems
alert
the
owner
or
operator
to
potential
container
overfills,
which
are
a
common
cause
of
discharges.
Because
this
is
a
requirement
in
the
current
rule,
no
phase­
in
is
necessary.

Alternatives.
Under
the
deviation
provision
at
§112.7(
a)(
2),
you
may
substitute
"procedures"
or
other
measures
that
provide
equivalent
environmental
protection
as
any
of
the
alarm
systems
mandated
in
the
rule
if
you
can
explain
your
reasons
for
nonconformance.
Such
procedures
might
include
conformance
to
UST
rules
if
you
can
show
that
such
conformance
provides
equivalent
environmental
protection
to
the
SPCC
requirement.

Monitoring.
We
agree
with
the
commenter
that
a
person
must
be
present
to
monitor
a
fast
response
system
to
prevent
overfills
and
have
amended
the
rule
accordingly.
We
disagree
that
the
requirement
for
alarm
devices
should
not
apply
when
a
person
is
present,
because
human
error,
negligence,
on
inattention
may
still
occur
in
those
cases,
necessitating
some
kind
of
alarm
device.

XI
­
B(
9)
Removal
of
accumulated
oil
within
72
hours
­
§112.8(
c)(
10)

Background:
Section
112.7(
e)(
2)(
x)
of
the
current
rule
requires
an
owner
or
operator
of
an
onshore
bulk
storage
facility
to
promptly
correct
visible
oil
leaks
that
result
in
a
loss
of
oil
from
tank
seams,
gaskets,
rivets,
and
bolts
sufficiently
large
enough
to
cause
the
accumulation
of
oil
in
diked
areas.
In
1991,
we
reproposed
this
requirement
in
redesignated
§112.8(
c)(
10).
We
also
proposed
to
require
that
an
owner
or
operator
completely
remove
accumulated
oil
or
oil­
contaminated
materials
within
72
hours
from
the
time
the
discharge
occurred.
We
noted
that
this
time
frame
was
consistent
with
the
requirement
for
diked
areas
in
proposed
§112.7(
c),
where
we
proposed
to
require
that
the
entire
containment
system
be
impervious
to
oil
for
72
hours.

Comments:
Bioremediation.
"...
the
72­
hour
requirement
would
effectively
limit
the
choice
of
cleanup
technologies
to
those
that
emphasize
speed.
This
would
preclude
the
use
of
other
proven
technologies,
such
as
in­
situ
bioremediation,
which
cannot
be
completed
in
a
72­
hour
period."
(42,
48,
67,
91,
99,
102,
133,
175,
187).
251
"Bioremediation
techniques
and
other
measures
which
may
be
used
under
existing
laws
are
less
expensive
and
create
less
waste
than
removal
procedures.
No
materials
are
transported,
which
eliminates
the
risks
inherent
in
hauling
the
`contaminated'
dirt.
In
short,
fixing
the
problem
`on
the
spot'
is
often
very
good
advice."
(42)

72­
hour
cleanup
standard.

Support
for
proposal.
"As
noted
in
the
preamble,
such
containment
would
have
to
be
impervious
to
spilled
product
for
72
hours."
(L17)

Opposition
to
proposal.
We
should
delete
the
requirement
or
change
it
to
a
recommendation.
(72)

Expensive.
"To
require
total
cleanup
of
spilled
oil
and
material
within
72
hours
in
all
cases
would
be
impractical,
costly,
and
impossible
in
some
cases."
(22,
37,
72,
90,
99,
170,
187)
The
72­
hour
requirement
is
excessive
and
unnecessary
because
spill
response
procedures
are
described
in
the
SPCC
Plan.
(25)
The
requirement
would
be
particularly
costly
for
remote
facilities.
(37)

Health
or
safety
hazard.
"Depending
on
site
conditions,"
72
hour
cleanup
"could
jeopardize
worker
safety
and
health."
(48,
67,
91,
102,
170,
175,
187)

Impractical
or
impossible.
"To
require
total
cleanup
of
spilled
oil
and
material
within
72
hours
in
all
cases
would
be
impractical,
costly,
and
impossible
in
some
cases."
(22,
48,
57,
72,
83,
92,
98,
102,
107,
125,
143,
153,
170,
175,
184,
189,
L2)
Removal
within
72
hours
from
the
time
of
the
spill
would
be
difficult
for
unattended
facilities.
(72)
Texas
allows
on­
site
soil
remediation
or
treatment.
(99)
"Frequently
it
is
not
technically
feasible
to
remove
contaminated
soil
due
to
structural
concerns
or
volume
considerations.
State
regulations
often
will
not
allow
for
treatment
methods
which
are
commonly
employed
until
a
permit
has
been
issued,
requiring
considerably
more
time
than
72
hours."
(153)
"The
Company
agrees
that
`accumulated
oil'
(i.
e.,
free
product)
be
cleaned
out
of
a
containment
structure,
however,
`oil
contaminated
materials'
should
not
be
a
concern.
This
could
be
construed
to
mean
the
walls
and
floor
of
a
clay
dike
used
for
containment."
(125,164)

Land
disposal
problems.
"Also,
to
dispose
of
a
waste
sometimes
takes
as
much
as
two
months
while
waste
samples
are
laboratory
tested,
arrangements
are
made
with
a
disposal
facility,
and
State
approval
is
obtained
to
ship
the
wastes
off
site.
In
many
cases,
the
ideal
location
to
hold
the
waste
until
shipment
offsite
is
within
the
secondary
containment
area
of
the
tank
which
experienced
the
spill."
(92,
125)
"To
disallow
any
other
method
than
complete
removal
of
oil
contaminated
soil
from
diked
areas
in
these
circumstances
serves
no
useful
purpose.
Moreover,
it
compounds
landfill
disposal
capacity
problems
and
diverts
funds
that
could
be
more
effectively
used
to
address
other
more
pressing
environmental
problems."
(99,
187)
252
Low
risk,
historic
spills.
"More
importantly,
at
older
facilities
there
may
be
historically
contaminated
soil
from
past
spills
within
diked
areas.
These
soils
pose
no
threat
of
`escape
to
surface
waters.
The
requirement
to
clean
up
in
these
instances
would
be
prohibitively
expensive
and
would
yield
no
benefit."
(72,
164)

Small
spills.
"...
API
believes
clarification
is
needed
with
regard
to
cleanup
of
small
discharges
as
opposed
to
larger
discharges
within
the
proposed
72
hour
cleanup
period."
(67,
77,
91,
175,
187,
L20)

Unnecessary.
It
is
unnecessary
to
remove
all
spilled
oil
within
72
hours
if
the
containment
system
is
designed
to
be
impervious
to
oil
for
a
longer
period
of
time.
(57)
Since
regulated
facilities
have
secondary
containment,
discharged
oil
and
oil­
contaminated
materials
would
be
contained.
Therefore,
the
72­
hour
requirement
is
unnecessary.
(107,
189)

Prevention
­
plastic
film.
Covering
soil
with
plastic
film
may
be
an
acceptable
method
to
prevent
stormwater
contamination
during
remediation.
(99)

Terms
to
clarify.

Accumulated
oil,
oil­
contaminated
materials.
We
should
clarify
the
terms
accumulated
oil
and
oil­
contaminated
materials.
(57,
62,
125,
153)
Asks
for
clarification
of
accumulated
oil,
because
a
slow
leak
or
drip
may
result
in
the
accumulation
of
a
small
puddle
of
oil
in
a
large
containment
area
with
limited
access.
In
this
situation,
the
risk
to
employees
may
be
greater
than
the
risk
to
the
environment.
(62)

Completely
removed.
We
should
clarify
the
term
completely
removed.
(57)

Spill
event.
Our
reference
to
a
spill
event
in
§112.8(
c)(
10)
is
inconsistent
with
the
definition
in
§112.2(
s).
(29)

Time
calculations.
"API
notes
that
the
time
the
spill
occurred
will
not
always
be
known.
Therefore,
any
such
requirement
should
be
based
on
the
time
the
spill
is
first
discovered."
(67,
72,
91,
92,
102,
153,
164,
175)

Clarification
needed.
Questions
how
72­
hour
period
will
be
calculated.
(67,
79,
82,
85,
91,
92,
95,
102,
153,
164,
175)

Time
cleanup­
alternatives.

Immediately.
"Accumulated
oil
should
be
cleaned
up
immediately,
and
not
within
the
72
hours
proposed."
(27)
253
72
hours
after
observation.
"GM
recommends
that
accumulated
oil
of
sufficient
volume,
i.
e.,
greater
than
50
gallons,
in
containment
structures
should
be
removed
expediently
but
no
longer
than
72
hours
after
observation."
(90,
153)

As
soon
as
possible.
We
should
require
that
the
owner
or
operator
complete
clean­
up
operations
as
soon
as
"possible"
or
"practicable,"
or
"after
the
spill
is
discovered."
(
48,
67,
83,
91,
102,
133,
143)

Expeditiously.
(48,
67,
85,
91,
95,
102,
117,
133,
143)

Initiation
within
72
hours.
We
should
amend
the
proposed
requirement
to
state
that
clean­
up
efforts
must
begin
within
72
hours
or
within
a
period
of
time
sufficient
to
permit
the
clean­
up
of
oil
before
the
containment
system
begins
to
leak.
(57)
"As
suggested
above,
this
requirement
should
be
changed
to
allow
that
within
72
hours
and/
or
as
soon
as
feasible
a
spill
will
be
responded
to
and
cleanup
initiated
in
order
to
ensure
that
navigable
waters
are
not
impacted."
(66,
98,
125,
170,
184,189,
L2,
L20)
We
should
require
the
"prompt
removal
of
precipitation
from
containment
areas"
within
72
hours.
We
should
require
treatment
of
the
accumulated
precipitation
from
the
containment
areas,
if
necessary,
within
72
hours
after
the
precipitation
had
ended.
(80)

So
as
to
prevent
further
environmental
impact.
"EPA
should
clarify
this
requirement
to
state
that
`accumulated
spills
should
be
sufficiently
removed
within
72
hours
so
as
to
prevent
further
environmental
impact."
(107)

More
than
72
hours.
"If
the
spilled
oil
is
contained
or
controlled
or
is
being
remediated,
then
there
should
be
additional
time
given
for
the
response
measures
in
process,
especially
if
there
are
difficulties
encountered
in
the
cleanup."
(22)
"Nor
is
it
necessary
to
remove
all
spilled
oil
within
seventy­
two
hours
if
the
containment
system
is
designed
to
be
impervious
to
oil
for
a
much
longer
period
of
time."
(57,
66,
98,
125,
170,
184,
189,
L2)

96
hours.
"A
96
hour
time
frame
would
still
meet
the
general
intent
of
the
rule
buy
allowing
unattended
weekend
operation,
but
still
provide
adequate
response
time
once
the
event
is
discovered
without
putting
the
facility
in
jeopardy
of
not
complying
with
the
regulations."
(87)

144
hours,
at
least.
"Alyeska
recommends
that
EPA
at
least
double
this
time
requirement."
(77)

Response:
Support
for
proposal.
We
appreciate
commenter
support.

Applicability.
The
requirement
to
clean
up
accumulations
of
oil
is
applicable
to
all
facilities,
large
and
small.
The
size
of
the
accumulation
is
irrelevant,
as
any
accumulation
may
migrate
to
navigable
waters
or
adjoining
shorelines.
The
damage
to
the
environment
may
be
the
same,
depending
on
the
amount
discharged.
254
72­
hour
cleanup
standard.
We
have
deleted
the
proposed
72­
hour
cleanup
standard
because
it
would
preclude
bioremediation.
We
also
agree
that
under
certain
circumstances,
such
a
time
limit
might
jeopardize
worker
safety
and
health.
Therefore,
we
have
maintained
the
current
standard
that
visible
discharges
must
be
promptly
removed.
Prompt
removal
means
beginning
the
clean­
up
immediately
after
discovery
of
the
discharge,
or
immediately
after
taking
any
action
to
prevent
fire
and
explosion
or
other
threats
to
worker
health
and
safety.
However,
actions
to
prevent
threats
of
fire
or
explosions
may
not
be
used
to
unreasonably
delay
such
efforts.
The
size
of
the
accumulation
is
irrelevant,
as
any
accumulation
may
migrate
to
navigable
waters
or
adjoining
shorelines.

Extent
of
and
methods
of
cleanup.
No
matter
what
method
of
clean­
up
method
you
use,
you
must
completely
remove
the
accumulated
oil.
Any
effective
method
that
complies
with
all
other
applicable
laws
and
regulations
is
acceptable.
Bioremediation
may
be
one
acceptable
method
of
clean­
up.
Acceptable
methods
will
depend
on
the
weather,
other
environmental
conditions,
and
good
engineering
practice.
If
the
clean­
up
method
chosen
undermines
the
stability
of
a
dike,
the
owner
or
operator
must
repair
the
dike
to
its
previous
condition.

Prevention
­
plastic
film.
We
support
all
efforts
to
prevent
contamination
of
navigable
waters.
An
owner
or
operator
may
choose
to
spread
plastic
film
over
the
diked
area
to
prevent
stormwater
contamination,
or
use
some
other
acceptable
method.
However,
the
owner
or
operator
must
dispose
of
the
film
properly
if
he
chooses
that
method.

Terms
to
clarify.

Accumulated
oil,
oil­
contaminated
materials.
An
"accumulation
of
oil"
means
a
discharge
that
causes
a
film
or
sheen
or
a
sludge
or
emulsion
in
a
diked
area.
See
40
CFR
110.3(
b).
The
term
"oil­
contaminated
materials"
is
not
used
in
the
final
rule,
because
oil
must
accumulate
on
something
such
as
materials
or
soil.
Therefore,
the
term
is
redundant.
Instead,
in
the
final
rule
we
use
the
term
"accumulation
of
oil",
which
includes
anything
on
which
the
oil
gathers
or
amasses
within
the
diked
area.
Such
accumulation
may
include
oil­
contaminated
soil
or
any
other
oil­
contaminated
material
within
the
diked
area
that
impairs
(i.
e.,
decreases
the
capacity
of)
the
secondary
containment
system.

Completely
removed.
We
no
longer
use
the
term
"completely
removed"
in
§112.8(
c)(
10).
The
requirement
to
remove
any
accumulation
of
oil
means
cleanup
of
all
such
accumulations.

Spill
event.
We
have
removed
the
term
"spill
event"
from
the
proposed
paragraph
and
note
that
we
agree
with
the
commenter
who
noted
that
the
reference
to
a
"spill
event,"
or
a
"discharge
as
described
in
§112.1(
b),"
within
a
diked
area
is
inconsistent
with
that
concept.

XI
­
B(
10)
Mobile
and
portable
containers
­
§112.8(
c)(
11)
255
Background:
Under
§112.7(
e)(
2)(
xi)
of
the
current
rule,
an
owner
or
operator
must
locate
mobile
or
portable
containers
so
as
to
prevent
spilled
oil
from
reaching
navigable
waters.
He
must
provide
secondary
containment
for
the
largest
single
compartment
or
tank.
He
must
locate
his
facility
where
it
will
not
be
subject
to
periodic
flooding
or
washout.
In
1991,
we
proposed
to
designate
§112.7(
e)(
2)(
xi)
of
the
current
rule
as
§112.8(
c)(
11),
and
to
change
the
requirement
for
secondary
containment
to
a
recommendation.
We
also
proposed
to
recommend,
not
require,
that
an
owner
or
operator
locate
a
mobile
or
portable
oil
storage
container
in
an
area
not
subject
to
periodic
flooding
or
washout.

Comments:
Floods.
"...
portable
tanks
are
not
the
only
tanks
which
should
be
kept
out
of
the
flood
plain.
The
recommendation
should
be
extended
to
all
new
equipment."
(
111)

Requirement
or
recommendation.
"Tanks
should
be
required
to
be
located
in
areas
not
subject
to
flooding."
(27)
We
should
amend
the
rule
to
require
locating
mobile
or
portable
containers
to
"prevent
discharges
from
entering
navigable
waters."
(67)

Secondary
containment
­
requirement
or
recommendation.

Recommendation.
We
should
place
the
secondary
containment
recommendation
in
another
document.
(121)
"Secondary
containment
for
mobile
or
portable
tanks
should
be
left
as
a
recommendation.
In
addition,
some
basic
security
procedures
and
a
contingency
plan
may
be
adequate
for
spill
prevention
and
control
from
mobile
and
portable
tanks.
Further
investigation
into
the
spill
history
from
these
types
of
tanks
should
be
conducted
to
assess
the
environmental
threat
from
such
tanks."
(190)

Time
limits.
"Mobile
and
portable
tanks
should
be
defined
more
clearly.
Ohio
EPA
recommends
defining
such
a
tank
as
one
which
is
in
place
on
a
contiguous
property
for
10
days
or
less."
(27)

Response:
Floods.
We
deleted
the
proposed
recommendation
on
siting
of
mobile
containers
in
this
rule
because
we
do
not
wish
to
confuse
the
regulated
public
over
what
is
mandatory
and
what
is
discretionary.
These
rules
contain
only
mandatory
requirements.

Requirement
or
recommendation.
We
agree
that
the
purpose
of
the
rule
is
to
prevent
discharges
from
becoming
discharges
as
described
in
§112.1(
b).
Therefore,
in
response
to
comment,
we
have
modified
the
proposed
rule
to
require
positioning
or
locating
mobile
or
portable
containers
to
prevent
"a
discharge
as
described
in
§112.1(
b),"
rather
than
"oil
discharges."
"A
discharge
as
described
in
§112.1(
b)"
is
a
more
inclusive
term,
tracking
the
expanded
scope
of
the
amended
CWA.

Secondary
containment.
In
response
to
comments,
we
have
maintained
the
secondary
containment
requirement
in
the
current
rule
because
secondary
containment
is
256
necessary
for
mobile
containers
for
the
same
reason
that
it
is
necessary
for
fixed
containers;
to
prevent
discharges
from
becoming
discharges
as
described
in
§112.1(
b).
Secondary
containment
must
also
be
designed
so
that
there
is
ample
freeboard
for
anticipated
precipitation.
We
have
therefore
amended
the
rule
on
the
suggestion
of
a
commenter
to
provide
for
freeboard.
We
agree
with
the
commenter
that
the
amount
of
freeboard
should
be
sufficient
to
contain
a
25­
year
storm
event,
but
are
not
adopting
that
standard
because
of
the
difficulty
and
expense
for
some
facilities
in
securing
recent
information
concerning
25­
year,
24­
hour
storm
events
at
this
time.
Should
that
situation
change,
we
will
reconsider
proposing
such
a
standard
in
rule
text.
Freeboard
sufficient
to
contain
precipitation
is
freeboard
according
to
industry
standards,
or
in
an
amount
that
will
avert
a
discharge
as
described
in
§112.1(
b).
Should
secondary
containment
not
be
practicable,
you
may
be
able
to
deviate
from
the
requirement
under
§112.7(
d).

We
clarify
that
the
secondary
containment
requirement
relates
to
the
capacity
of
the
largest
single
compartment
or
container.
Permanently
manifolded
tanks
are
tanks
that
are
designed,
installed,
or
operated
in
such
a
manner
that
the
multiple
containers
function
as
a
single
storage
unit.
Containers
that
are
permanently
manifolded
together
may
count
as
the
"largest
single
compartment,"
as
referenced
in
the
rule.

Time
limits.
We
decline
to
place
a
time
limitation
in
a
definition
of
mobile
or
portable
containers.
Mobile
or
portable
containers
may
be
in
place
for
more
than
ten
days
and
still
be
mobile.
Mobile
containers
that
are
in
place
for
less
than
10
days
may
still
experience
a
discharge
as
described
in
§112.1(
b).

XI
­
C:
Facility
transfer
operations,
pumping,
and
facility
process
­
§112.8(
d)

XI
­
C(
1)
Buried
piping
­
protective
coatings
and
cathodic
protection

112.8(
d)(
1)

Background:
Section
112.7(
e)(
3)(
i)
of
the
current
rule
requires
an
owner
or
operator
to
cathodically
protect
and
provide
protective
wrapping
and
coating
on
all
buried
piping
installations
if
soil
conditions
warrant.
In
1991,
we
proposed
to
redesignate
§112.7(
e)(
3)(
i)
as
§112.8(
d)(
1).
In
that
proposal
we
recommended
that
an
owner
or
operator
place
all
piping
installations
aboveground,
where
possible.
We
also
proposed
to
require
that
an
owner
or
operator
cathodically
protect
and
provide
protective
wrapping
and
coating
on
new
or
replaced
buried
piping,
with
an
alternative
option
to
comply
with
other
corrosion
protection
standards
for
buried
piping
in
40
CFR
part
280,
the
underground
storage
tank
(UST)
regulation.

We
proposed
to
continue
to
require
that
an
owner
or
operator
carefully
inspect
buried
pipeline
for
deterioration
if
a
pipeline
section
is
exposed
for
any
reason.
We
proposed
that
if
an
owner
or
operator
finds
corrosion
damage,
he
must
inspect
the
damage
and
take
corrective
action
as
indicated
by
the
magnitude
of
damage.

Finally,
in
the
preamble,
we
encouraged
owners
or
operators
to
place
piping
installations
in
leak­
proof
galleys
that
feed
into
the
facility's
oil/
water
separator.
We
257
also
proposed
to
recommend
that
buried
piping
installations
comply
to
the
extent
applicable
with
all
of
the
relevant
part
280
provisions.

Comments:
Aboveground
piping
recommendation.

Support
for
recommendation.

All
piping.
Owners
or
operators
should
place
all
piping
aboveground
to
help
detect
piping
system
problems
before
there
is
a
discharge.
(L1)

New
piping.
We
should
revise
§112.8(
d)(
1)
to
recommend
that
owners
or
operators
place
all
new
piping
aboveground,
where
appropriate.
It
would
be
"onerous,
costly,
and
not
necessarily
protective
of
navigable
waters"
to
move
all
existing
buried
lines
aboveground.
(67)

Editorial
suggestion.
"The
first
sentence
in
proposed
40
CFR
112.8(
d)(
1)
should
be
properly
reworded
(i.
e.,
remove
`shall'
to
read,
`It
is
recommended
that
all
piping
be
placed
aboveground,
where
possible."
(79,
102)

Opposition
to
recommendation.
The
recommendation
is
"a
clear
safety
problem
if
followed
as
recommended
by
the
agency.
...
Above
ground
installations
do
not
provide
the
requisite
degree
of
worker
safety,
because
of
the
tripping
hazard,
that
Delhi
seeks
to
attain."
(34)

Buried
piping
recommendation
­
part
280.

Support
for
requirement.
The
rule
should
"require
–
rather
than
recommend,
that
buried
piping
comply
with
the
corrosion
protection
provisions
of
40
CFR
part
280."
(44,
121)

Recommendations
not
followed.
"Also,
practices
for
integrity
testing
and
for
installation
of
pipes
pursuant
to
40
CFR
280
should
be
changed
from
`recommended'
practices
to
`required'
practices.
Our
experience
is
that
recommendations
without
standards
are
not
usually
followed."
(111)

Corrosion
protection.

Support
for
proposal.
Applying
protective
coating
and
cathodic
protection
on
buried
piping
provides
sufficient
leak
protection.
(34)
We
cannot
enforce
the
current
requirement
for
protecting
buried
piping
installations
"if
soil
conditions
warrant."
(121)
"MDE
strongly
supports
amendments
to"
§112.8(
d)(
1).
(135,
L17)

Opposition
to
proposal.
258
Coating
only.
"New
and
replacement
piping
should
include
protective
coating.
Cathodic
protection
should
be
required
only
when
soil
conditions
require
it.
Tests
to
determine
the
need
for
cathodic
protection
are
very
specific
and
should
be
used
to
identify
those
locations
requiring
the
protection."
(114)

Ineffective.
"Protective
coating
and
cathodic
protection
will
not
prevent
a
discharge
of
oil
to
the
environment
in
the
event
of
a
pipe
fracture,
nor
will
such
protection
be
able
to
detect
a
leak
if
one
occurs.
The
practice
of
using
double
walled
pipe
or
secondary
containment
and
product
sensitivity
leak
detection
for
new
installations
is
currently
required
by
NJDEPE."
(147)

Keep
current
rule.
An
owner
or
operator
should
protect
new
buried
piping
"where
soil
conditions
support
the
operation
of
a
corrosion
system
and
where
there
is
a
history
of
external
buried
piping
corrosion
that
can
be
controlled
by
corrosion
protection."
(67,
85,
114,
143)

Repairs.
"EPA
should
clarify
that
only
the
section
of
the
line
undergoing
repair
must
be
retrofitted
with
this
corrosion
protection."
It
would
be
very
costly
to
retrofit
the
entire
line.
(83,
88,
102)

Coating
only
on
replaced
sections.
"Placing
cathodic
protection
on
sections
of
replaced
piping
is
unwieldy
and
not
technically
feasible
because
the
cathodic
protection
requires
considerable
maintenance.
Bethlehem
endorses
the
use
of
cathodic
protection
when
an
entire
pipeline
is
replaced
and
protective
wrapping
on
all
replaced
sections
of
pipe."
(88)

Leak­
proof
galleys.
Our
recommendation
for
owners
or
operators
to
install
leak­
proof
galleys
under
aboveground
piping
is
redundant
and
economically
unjustifiable,
because
owners
or
operators
easily
can
inspect
and
maintain
aboveground
piping,
and
because
aboveground
piping
is
often
placed
within
secondary
containment
that
drains
to
oil/
water
separators.
(25,
68)

Response:
Support
for
proposal.
We
appreciate
commenter
support.

Aboveground
piping
recommendation.
While
we
have
deleted
the
proposed
recommendation
from
the
rule
text
because
we
do
not
wish
to
confuse
the
regulated
public
over
what
is
mandatory
and
what
is
discretionary,
we
still
believe
that
piping
should
be
placed
aboveground
whenever
possible
because
such
placement
makes
it
easier
to
detect
discharges.
The
decision
to
place
piping
aboveground
might
include
consideration
of
safety
and
traffic
factors.

Buried
piping
recommendation
­
part
280.
We
have
deleted
the
recommendation
from
the
proposed
rule
that
all
buried
piping
installations
comply
to
the
extent
practicable
with
40
CFR
part
280,
because
we
are
excluding
recommendations
from
this
rule
to
avoid
confusion
with
what
is
mandatory
and
what
is
discretionary.
Also,
some
buried
piping
259
now
subject
to
part
112
will
be
subject
only
to
40
CFR
part
280
or
a
State
program
approved
under
40
CFR
part
281
under
this
rule.
See
§112.1(
d)(
4).

Corrosion
protection.
Based
on
EPA
experience,
we
believe
that
all
soil
conditions
warrant
protection
of
new
and
replaced
buried
piping.
EPA's
cause
of
release
study
indicates
that
the
operational
piping
portion
of
an
underground
storage
tank
system
is
twice
as
likely
as
the
tank
portion
to
be
the
source
of
a
discharge.
Piping
failures
are
caused
equally
by
poor
workmanship
and
corrosion.
Metal
areas
made
active
by
threading
have
a
high
propensity
to
corrode
if
not
coated
and
cathodically
protected.
See
53
FR
37082,
37127,
September
23,
1988;
and
"Causes
of
Release
from
US
Systems,"
September
1987,
EPA
510­
R­
92­
702.
If
you
decide
to
deviate
from
the
requirement,
for
example,
to
provide
an
alternate
means
of
protection
other
than
coating
or
cathodic
protection,
you
may
do
so,
but
must
explain
your
reasons
for
nonconformance,
and
demonstrate
that
you
are
providing
equivalent
environmental
protection.
A
deviation
which
seeks
to
avoid
coating
or
cathodic
protection,
or
some
alternate
means
of
buried
piping
protection,
on
the
grounds
that
the
soil
is
somehow
incompatible
with
such
measure(
s),
will
not
be
acceptable
to
EPA.

A
"new"
or
"replaced"
buried
piping
installation
is
one
that
is
installed
30
days
or
more
after
the
date
of
publication
of
this
rule
in
the
Federal
Register.
We
have
deleted
the
words
"new"
and
"replaced"
from
the
proposed
language
and
substituted
this
specific
date
so
the
effective
date
is
clearer
to
the
regulated
community.
Under
the
current
rule,
you
have
an
obligation
to
provide
buried
piping
installations
with
protective
wrapping
and
coating
only
if
soil
conditions
warrant
such
measures.
Under
the
revised
rule,
you
must
provide
such
wrapping
and
coating
for
new
or
replaced
buried
piping
installations
regardless
of
soil
conditions.

You
should
consult
a
corrosion
professional
before
design,
installation,
or
repair
of
any
corrosion
protection
system.
Any
corrosion
protection
you
provide
should
be
installed
according
to
relevant
industry
standards.
When
piping
is
replaced,
you
must
protect
from
corrosion
only
the
replaced
section,
although
protection
of
the
entire
line
whenever
possible
is
preferable.
Equipping
only
a
small
portion
of
piping
with
corrosion
protection
may
accelerate
corrosion
rates
on
connected
unprotected
piping.
While
we
agree
that
corrosion
protection
might
not
prevent
all
discharges
from
buried
piping,
it
is
an
important
measure
because
it
will
help
to
prevent
most
discharges.

We
disagree
that
we
should
require
only
protective
coating
and
not
cathodic
protection.
Protective
coating
and
wrapping
and
cathodic
protection
provide
the
maximum
feasible
leak
prevention
technology.

We
note
that
no
strategy
can
prevent
all
discharges
from
buried
piping,
but
corrosion
protection
and
coating
will
help
prevent
most
discharges.

Double­
walled
piping.
Double­
walled
piping
or
secondary
containment
or
sensitive
leak
detection
for
buried
piping
may
be
acceptable
as
a
deviation
from
the
requirements
of
this
paragraph
under
§112.7(
a)(
2)
if
you
explain
your
reasons
for
nonconformance
with
260
the
requirement
and
show
that
the
means
you
selected
provides
equivalent
environmental
protection
to
the
requirement.
However,
we
will
not
require
such
measures
because
we
did
not
propose
them.

Leak­
proof
galleys.
We
have
not
included
such
a
recommendation
in
the
final
rule,
because
all
final
rule
provisions
are
mandatory.

XI
­
C(
2)
Terminal
connections
­
§112.8(
d)(
2)

Background:
Section
112.7(
e)(
3)(
ii)
of
the
current
rule
requires
an
owner
or
operator
to
cap
or
blank­
flange
an
oil
pipeline
terminal
connection
when
it
is
not
in
service
or
is
in
standby
service
for
an
extended
time.
In
1991,
we
proposed
to
redesignate
§112.7(
e)(
3)(
ii)
as
§112.8(
d)(
2),
and
to
clarify
that
"an
extended
time"
is
"six
months
or
more."

Comments:
Support
for
proposal.
"Consistency
for
determining
when
loading/
unloading
connections
must
be
securely
capped
or
blank­
flanged
will
be
promoted
by
specifying
what
constitutes
`an
extended
time',
and
NJDEPE
supports
the
specified
time
period
of
six
months."
(147)

Opposition
to
proposal.
The
rule
should
be
rewritten
as
follows:
"When
piping
is
not
in
service
or
is
not
in
standby
service...."
"Typically
piping
that
is
in
standby
service
is
only
needed
in
emergency
situations
or
when
there
is
an
operational
problem.
...
It
is
not
appropriate
for
this
requirement
to
apply
to
standby
piping,
especially
if
the
piping
must
be
put
into
service
quickly
during
an
emergency
to
insure
the
safe
operation
of
the
facility."
(67,
102)

Response:
We
appreciate
commenter
support.
We
have
decided
to
keep
the
current
standard
of
requiring
capping
or
blank­
flanging
terminal
connections
when
such
piping
is
not
in
service
or
is
in
standby
for
an
extended
time
in
order
to
maintain
flexibility
for
variable
facilities
and
engineering
conditions.
We
define
"an
extended
time"
in
reference
to
industry
standards
or
at
a
frequency
sufficient
to
prevent
discharges.
We
disagree
with
commenters
that
the
requirement
should
not
apply
to
piping
that
is
not
in
standby
service
because
some
discharges
may
be
caused
by
loading
or
unloading
oil
through
the
wrong
piping
or
turning
the
wrong
valve
when
the
piping
in
question
was
actually
out­
of­
service.
Typically,
piping
that
is
in
standby
service
is
only
needed
in
emergency
situations
or
when
there
is
an
operational
problem.
In
the
rare
situations
when
such
piping
is
needed
immediately,
the
owner
or
operator
may
remove
the
cap
or
blank­
flange
to
return
the
piping
to
service.

XI
­
C(
3)
Aboveground
valves
and
piping;
buried
piping
­
§112.8(
d)(
4).

XI
­
C(
3)­
1
Inspection
of
aboveground
valves,
piping,
and
appurtenances
Background:
Under
§112.7(
e)(
3)(
iv)
of
the
current
rule
(redesignated
in
the
final
rule
as
§112.8(
d)(
4)),
an
owner
or
operator
must
regularly
inspect
all
aboveground
valves
261
and
pipelines.
Operating
personnel
must
assess
the
general
conditions
of
items,
such
as
flange
joints,
expansion
joints,
valve
glands
and
bodies,
catch
pans,
pipeline
supports,
locked
valves,
and
metal
surfaces.
In
1991,
we
proposed
that
examinations
of
aboveground
valves
and
piping
must
be
monthly,
and
must
include
appurtenances.

In
1991,
we
recommended
in
§112.8(
d)(
4)
that
all
valves,
pipes,
and
appurtenances
conform
to
relevant
industry
codes,
such
as
ASME
standards.

Comments:
Applicability.

Electrical
equipment.
"This
requirement
would
impose
an
extremely
heavy
burden
on
the
electric
utility
industry
if
maintained
in
the
final
rule.
The
utility
industry
has
millions
of
pieces
of
equipment
in
tens
of
thousands
of
facilities
that
could
be
subject
to
the
SPCC
requirements,
some
in
remote
areas.
It
would
be
extremely
time­
consuming
and
expensive
to
require
that
each
of
these
be
inspected
monthly."
(125)

Large
facilities.
We
should
exempt
from
the
monthly
examination
requirement,
piping
systems
associated
with
large
tanks
with
a
storage
capacity
greater
than
100,000
gallons.
(90)

Buried
piping
recommendation.

Support
for
recommendation.
"ACMS
agrees
that
all
buried
piping
should
be
tested
as
proposed."
(51,
87,
107,
168)

Requirement
instead.
"ATA
believes
that
such
testing
is
reasonable
and
in
accordance
with
good
engineering
practices.
In
order
to
provide
sufficient
environmental
protection
and
to
minimize
industry
remediation
costs,
such
testing
should
be
required
rather
than
recommended.
Also,
it
should
apply
to
all
SPCCregulated
facilities,
not
only
large
facilities
(greater
than
42,
000
gallons)
as
EPA
has
suggested."
(87,
107,
168)

Editorial
suggestion.
"All
aboveground
valves,
piping
and
appurtenances
in
oil
service
should
be
visually
inspected
regularly,
monthly
or
more
frequently
if
necessary,
and
they
shall
be
subject
to
an
annual
examination
where
possible."
(143)

Industry
standards
recommendation.
"Similarly,
proposed
section
112.8(
d)(
4)
should
require,
rather
than
recommend,
that
all
valves,
pipes,
and
appurtenances
conform
to
relevant
industry
codes."
(44)
"This
is
also
the
place
to
require
that
piping
and
fittings
be
manufactured
and
assembled
to
industry
codes
(which
need
to
be
listed)
for
all
construction
beginning
after
the
effective
date
of
this
part."
(121)

Methods
of
inspection.
262
Pressure
testing.
"We
agree
that
monthly
visual
examinations
of
aboveground
piping
may
be
sufficient.
However,
a
more
sophisticated
method
of
heating
should
be
required
every
three
or
four
years,
such
as
pressure
testing."
(27)

Visual
examinations.
We
should
require
periodic
visual
examinations
"in
accordance
with
accepted
industry
standards."
(67,
83,
91,
102)

Monthly
inspection.

Support
for
proposal.
Support
for
the
§112.8(
d)(
4)
proposed
requirement
for
monthly
examinations
of
aboveground
valves,
piping,
and
appurtenances.
(27,
91)

Large
and
small
facilities.
Our
proposed
monthly
examination
should
be
a
requirement
for
large
facilities,
but
a
recommendation
for
small
facilities.
(135)

Opposition
to
proposal.

Costly.
Monthly
examinations
require
large
facilities
to
commit
financial
and
personnel
resources.
(77)
Monthly
examinations
are
too
restrictive
(155).
Unjustified
and
expensive.
(L30)

Difficult.
"GM
believes
that
all
aboveground
valves,
piping,
and
appurtenances
should
not
be
subject
to
mandatory
monthly
examinations
....
GM
believes
that
the
owner
should
be
provided
the
flexibility
to
periodically
examine
piping
systems
at
a
necessary
frequency
to
insure
leaks
and
failure
conditions
are
not
occurring.
Failure
of
aboveground
piping
system
are
unlike
underground
systems
where
corrosion
is
the
main
cause.
Aboveground
piping
and
appurtenances
failure
are
more
often
caused
by
accidental
damage
or
vibrational
fatigue."
(90)

Recommendation
instead.
"The
Agency
has
not
shown
that
this
requirement
is
necessary
to
reduce
any
risk
of
discharge
to
navigable
waters,
and
therefore
this
provision
should
remain
as
a
`should'
to
allow
for
the
exercise
of
good
engineering
practice."
(125,
136,
143,
155,
189)
"We
suggest
that
proposed
§§
112.8(
d)(
4)
and
(d)(
5)
be
recommendations
instead
of
requirements
for
facilities
that
store
more
than
42,
000
gallons."
(39)

Unnecessary.
We
should
delete
the
§112.8(
d)
requirements
since
they
are
unnecessary.
They
are
unduly
onerous,
since
discharges
emanating
during
transfer
operations
would
be
properly
contained
according
to
the
SPCC
Plan
for
that
facility.
Monthly
examinations
are
excessive,
unnecessary,
and
expensive.
(189,
L30)

Alternatives
to
monthly
testing.
263
Every
six
months.
"A
six
month
examination
period
combined
with
an
obligation
by
the
operator
to
be
alert
for
spills
that
could
result
from
failure
of
pipes
and
appurtenances
is
a
more
reasonable
and
economic
approach."
(77)

Owner/
operator
discretion.
The
owner
or
operator
should
determine
examination
frequency.
(90,
155)

Quarterly.
Examinations
should
be
performed
quarterly
­
not
monthly
­
for
exploration
and
production
facilities.
(114)
"Large
facilities
can
have
thousands
of
valves
and
miles
of
pipe,
and
even
visual
inspections
would
be
very
time­
consuming
and
costly.
Further,
there
is
some
question
as
to
whether
monthly
inspections
are
warranted;
the
condition
of
piping
and
valves
rarely
changes
significantly
in
one
month."
(175)

System
examinations.
We
should
not
require
monthly
examinations,
but
should
require
systems
examinations
with
sufficient
frequency
to
assure
safe
and
proper
maintenance
and
operations.
(184)

Clarification
needed.
We
did
not
explain
what
the
monthly
aboveground
examination
would
require.
(77)

Response:
Support
for
proposal.
We
appreciate
commenter
support.

Applicability.
Inspection
of
aboveground
valves,
piping,
and
appurtenances
must
be
a
requirement
to
help
prevent
discharges.
Such
valves,
piping,
and
appurtenances
often
are
located
outside
of
secondary
containment
systems,
and
often
do
not
have
double­
wall
protection
or
some
form
of
secondary
containment
themselves.
Therefore,
any
discharge
from
such
valves,
piping,
and
appurtenances
is
more
likely
to
become
a
discharge
as
described
in
§112.1(
b).
Examination
of
discharge
reports
from
the
Emergency
Response
Notification
System
(ERNS)
show
that
discharges
from
such
valves,
piping,
and
appurtenances
are
much
more
common
than
catastrophic
tank
failure
or
discharges
from
tanks.

Electrical
equipment.
The
requirements
of
this
paragraph
do
not
apply
to
electrical
utilities
and
other
facilities
with
oil­
filled
equipment
because
they
are
not
bulk
storage
facilities.

Exploration
and
production
facilities.
Regarding
the
comment
that
we
should
require
inspections
less
frequently
for
exploration
and
production
facilities,
the
point
is
moot.
Section
112.8
excludes
production
facilities
from
its
scope.

Large
facilities.
The
requirement
must
be
applicable
to
large
and
small
facilities
covered
by
this
section,
because
of
the
same
threat
of
discharge.

Editorial
suggestion.
We
agree
with
a
commenter
that
the
rule
applies
only
to
"oil­
handling"
piping
and
valves,
not
all
such
piping
and
valves,
which
may
be
unrelated
264
to
oil
activities.
However,
no
change
in
rule
text
is
necessary
because
the
entire
rule
applies
only
to
procedures,
methods,
or
equipment
that
are
involved
with
the
storage
or
use
of
oil.

Industry
standards
recommendation.
We
deleted
from
rule
text
the
recommendation
that
all
valves,
pipes,
and
appurtenances
conform
to
industry
standards,
because
we
do
not
wish
to
confuse
the
public
with
discretionary
items
in
a
mandatory
rule,
but
we
endorse
its
substance.
However,
we
do
endorse
conforming
with
industry
standards
and
codes
because
such
conformance
reflects
the
exercise
of
good
engineering
practice.

Monthly
inspection.
The
final
rule
maintains
the
current
standard
of
"regular"
inspections,
on
the
suggestion
of
commenters
who
noted
that
at
some
remote
sites
monthly
inspections
are
impractical,
especially
in
harsh
weather
conditions.
Furthermore,
we
agree
with
commenters
that
"regular"
inspections
are
inspections
conducted
"in
accordance
with
accepted
industry
standards,"
rather
than
the
monthly
proposed
standard.
You
must
include
appurtenances
in
the
inspection.
Inspections
may
be
either
visual
or
by
other
means,
including
pressure
testing.
However,
we
do
not
require
pressure
testing
or
any
other
specific
method.
We
agree
that,
subject
to
good
engineering
practice,
pressure
testing
every
three
or
four
years
may
be
warranted
in
addition
to
regular
inspection
of
aboveground
valves,
piping,
and
appurtenances.
However,
we
believe
that
regular
inspection
is
sufficient
to
help
prevent
discharges
and
will
not
impose
any
additional
requirements
at
this
time.

Aboveground
leaks.
In
response
to
the
comment
that
leaks
from
aboveground
piping
are
discovered
more
quickly
than
from
underground
storage
tanks,
we
note
that
leakage
may
occur
from
any
piping.
An
owner
or
operator
must
inspect
aboveground
valves,
piping,
and
appurtenances
to
prevent
such
leakage.

Integrity
testing.
In
response
to
the
comment
that
integrity
testing
is
impractical
for
piping
systems
associated
with
storage
tanks
designed
to
operate
as
a
gravity
system,
we
note
that
we
did
not
propose
testing
of
aboveground
piping.
In
response
to
the
comment
that
accidental
damage
or
vibrational
fatigue
most
often
causes
aboveground
system
failure,
we
note
that
these
conditions
may
become
apparent
when
the
owner
or
operator
inspects
the
general
conditions
of
aboveground
valves,
piping,
and
appurtenances.

Transfer
operations.
In
response
to
the
comment
that
changes
emanating
during
transfer
operations
would
be
properly
contained
according
to
the
SPCC
Plan
for
that
facility,
we
think
this
remark
is
unrelated
to
the
utility
of
preventive
testing
and
remediation.
Proper
containment
is
an
effective
control
measure
for
an
actual
discharge.

Visual
inspections.
Inspections
may
be
either
visual
or
by
other
means,
including
pressure
testing.
However,
we
do
not
require
pressure
testing
or
any
other
specific
method.
We
think
the
inspection
method
is
best
left
to
good
engineering
practice.
265
XI
­
C(
3)­
2
Integrity
and
leak
testing
of
buried
piping
­
§112.8(
d)(
4)

Background:
Under
current
rule
§112.7(
e)(
3)(
iv),
an
owner
or
operator
must
conduct
periodic
pressure
testing
for
piping
in
areas
where
facility
drainage
is
such
that
a
failure
might
lead
to
a
spill
event.
In
1991,
we
proposed
to
redesignate
§112.7(
e)(
3)(
iv)
as
§112.8(
d)(
4),
and
to
delete
the
periodic
pressure
testing
requirement
from
the
rule.
Instead,
we
proposed
to
recommend
annual
integrity
and
leak
testing
or
monthly
monitoring
of
buried
piping
following
the
requirements
of
40
CFR
part
280,
the
Underground
Storage
Tank
(UST)
regulations.
We
proposed
to
require
that
an
owner
or
operator
maintain
testing
or
monitoring
records
for
five
years.

Comments:
Applicability.

Double­
walled
tanks
and
piping.
The
configuration
of
a
vaulted
tank
is
unsuitable
for
monthly
examinations
we
proposed.
"VAST
(Vaulted
aboveground
storage
tank)
technology
also
requires
that
all
fittings
and
pipes
come
out
of
the
top
of
the
tank,
which
eliminates
the
possibility
of
leaking
from
the
valves,
pipes,
or
fittings
and
significantly
reduces
the
potential
for
corrosion."
(65)
Exterior
tanks
and
piping
systems
in
remote
locations
are
secondarily
contained
and
have
low­
level
alarms
connected
to
an
attended
facility.
(79)
"An
alternative
would
be
to
allow
double
walled
underground
piping
or
other
means
of
secondary
containment
for
the
pipe
itself
to
be
exempt
from
annual
testing
requirements.
This
type
of
piping
is
one
way
of
addressing
providing
secondary
containment
to
meet
RCRA
standards."
(87)

Manned
facilities,
aboveground
facilities,
cathodically
protected
facilities.
"...
discretion
should
be
applied
to
and
exceptions
from
periodic
buried
pipe
testing
should
be
established
for
manned
facilities,
aboveground
facilities,
and
cathodically
protected
facilities."
(192)

Support
for
recommendation.
"This
provides
for
maximum
flexibility
in
the
use
of
good
engineering
practices."
(39,
48,
66,
72,
95,
102,
103,
116,
150,
161,
175,
188,192,
L8,
L29)
Alternatives.

3
years.
"Oxychem
recommends
integrity
testing
be
required
on
underground
piping
every
three
years,
unless
failure
data
supports
more
frequent
testing."
(141)

3­
4
years.
"However,
a
more
sophisticated
method
of
heating
should
be
required
every
three
to
four
years,
such
as
pressure
testing.
...
Frequency
may
be
based
on
aquifer
use."
(27)

5
years.
"The
testing
for
underground
piping
should
be
conducted
once
every
five
years.
This
would
be
consistent
with
the
requirements
for
aboveground
piping
systems."
(L2,
L20)
266
Owner/
operator
discretion.
"Integrity
testing
of
buried
tanks,
piping
and
valves
should
be
discretionary
in
all
cases.
Cites
pollution
risk
of
testing.
(102,
136,
155,
175)

Periodic
testing.
We
could
make
part
112
more
cost­
effective
by
requiring
"periodic
testing
of
existing
piping
under
a
reasonable
compliance
schedule"
to
provide
additional
safeguards
without
the
risks
and
difficulties
the
proposed
recommendation
presented.
(L35)

Regular
basis.
We
should
require
testing
on
a
regular
basis.
(143)

Small
facilities.
We
should
allow
owners
or
operators
of
small
facilities
with
secondary
containment
to
use
good
engineering
practice
to
determine
the
testing
frequency.
(10)
We
should
allow
small
facilities
the
discretion
to
determine
testing
frequency,
but
require
owners
or
operators
of
large
facilities
to
conduct
the
monthly
monitoring.
(116,
182)

When
a
line
is
exposed.
"API
believes
that
buried
piping
should
be
inspected
for
corrosion
and
necessary
remedial
action
whenever
a
section
of
the
line
is
exposed."
(67,
91,
L30)

Opposition
to
recommendation.

Costly.
"It
would
be
impractical
and
extremely
costly
for
small
facilities
to
implement
the
recommended
integrity
and
leak
testing."
(34,
66,
115)
Annual
testing
would
interfere
with
essential
facility
operations.
(77)
The
need
to
monitor
buried
piping
systems
monthly
is
costly
and
a
significant
administrative
burden.
(90,
188)

Drawbacks.
"There
are
a
variety
of
drawbacks
with
performing
pressure
testing
of
piping
systems
more
frequently
than
site­
specific
conditions
indicate
are
necessary.
Pressure
testing
of
such
systems
often
results
in
the
generation
of
waste
materials
and
air
emissions
that
otherwise
would
not
have
resulted."
(102)
"Performing
annual
integrity
testing
of
pipes
and
valves
could
be
detrimental
to
the
life
expectancy
of
the
piping.
When
a
hydrostatic
integrity
test
is
performed,
the
piping
is
often
subjected
to
1.
5
times
its
design
pressure.
Annual
testing
will
very
likely
cause
undue
stress
on
the
piping
and
can
potentially
lead
to
premature
failure,
and
consequently,
releases
to
the
environment."
(141,
175)

Impractical
for
multiple
sites.
"However,
monthly
testing
is
not
practical
at
the
many
sites
we
have,
especially
those
sites
which
are
not
accessible
in
the
winter.
Our
fuel
piping
is
contained
within
a
secondary
enclosure.
If
a
leak
occurs,
the
product
will
be
contained
and
drained
into
a
containment
area
where
it
will
be
noticed.
The
tank
system
has
been
designed
to
prevent
any
contamination
to
the
environment
if
a
failure
should
occur."
(37,
79)
267
Inaccurate
predictor.
"Additionally,
all
the
test
would
show
is
that
the
piping
is
not
leaking
at
that
particular
moment.
It
would
not
be
an
accurate
predictor
of
the
future
integrity
of
the
line."
(34,
115)

Non­
operational
pipelines.
"Similarly,
the
pipeline
integrity
testing
program
would
be
too
onerous
to
impose
on
historic,
non­
operational
buried
pipelines,
the
location
of
which
are
not
know."
(35
)

Other
leak
prevention
instrumentation.
"Requiring
annual
tests
on
buried
piping
would
severely
limit
the
facility's
ability
to
receive
feedstocks
and
deliver
finished
products.
It
should
not
be
necessary
for
these
proposed
requirements
taking
into
consideration
the
other
leak
prevention
instrumentation
that
would
sound
alarms,
shut
off
pumps,
and
automatically
close
valves
to
isolate
sections
of
piping."
(25)

Piping
age,
size.
"Integrity
testing
of
underground
pipes
on
an
annual
basis
appears
too
stringent
and
should
be
scheduled
to
account
for
the
age
of
the
facility
(as
is
the
case
of
UST
regulations.)"
We
should
require
"testing
for
buried
piping
on
a
schedule
related
to
the
age
and
size
of
the
system,
with
greater
frequencies
for
older
and
larger
systems."
(89,
95,
102,
197,
L30)
(L30)

Requirement
instead.
"Annual
integrity
and
leak
testing
of
buried
piping
will
not
be
conducted
unless
it
is
made
a
requirements."
(27,
44,
51,
87,
107,
111,
168)
"Additionally,
given
the
relatively
higher
frequency
of
piping
leaks
compared
to
tank
leaks,
it
is
essential
that
facility
owners
or
operators
be
required
to
conduct
`annual
integrity
and
leak
testing
of
buried
piping
or
monitor
buried
piping
on
a
monthly
basis,
...,
a
requirement
similar
to
that
in
40
CFR
part
280."
(44)
We
should
change
the
proposed
§112.8(
d)(
4)
recommendation
to
a
requirement
or
delete
it.
(121)
"Proposed
112.8(
d)(
4)
should
be
a
requirement
since
piping
often
runs
outside
of
secondary
containment
systems.
Examination
of
ERNS
data
will
reveal
that
spills
from
piping
are
much
more
common
than
catastrophic
tank
failures
or
leaks
from
tanks.
Buried
piping
is
not
capable
of
being
visually
inspected
on
a
periodic
basis,
and
many
facilities
do
conduct
integrity
or
leak
testing
of
buried
piping
on
a
regular
basis."
(168)
"Because
secondary
containment
would
not
affect
underground
spill
pathways,
annual
testing
should
be
required
of
all
underground
piping
systems."
(L1)

Large
facilities.
"We
agree
with
the
SPCC
Task
Force
that
such
provisions
should
be
made
mandatory
for
large
facilities.
Buried
piping
which
is
unprotected
should
be
inspected
annually
regardless
of
facility
size."
(L17)

Too
restrictive.
The
proposed
testing
provision
is
too
restrictive.
(155)

Coast
Guard
rules.
The
buried
piping
recommendation
should
be
consistent
with
U.
S.
Coast
Guard
rules
for
testing
piping.
(143)
268
Length
and
nature
of
piping.
It
is
impractical
to
conduct
monthly
monitoring
of
lengthy
buried
piping
systems.
(66)
"UCC
believes
that
this
should
not
apply
to
piping
less
than
ten
feet
or
piping
which
conveys
limited
flow
annually."
(190)

Methods
of
testing.

Guidance
needed.
We
did
not
provide
guidance
on
the
types
of
accepted
integrity
testing
or
define
what
constitutes
a
leak
rate.
(66,
80)

Hydrostatic
testing.
Hydrostatic
testing
should
include
testing
with
the
product
and
gases
to
achieve
the
required
pressure.
(143)

Part
280.
Part
280
test
methods
and
monitoring
techniques
do
not
apply
to
all
buried
piping
systems,
such
as
large
diameter
piping,
booster
pumps,
and
valves
and
connections.
(66)
"Alyeska
also
is
confused
by
the
preamble's
statement
that
integrity
and
leak
testing
follow
40
CFR
part
280.
However,
there
is
no
mention
of
40
CFR
part
280
in
the
proposed
rule
for
integrity
and
leak
testing."
(77)

Visual
or
hydrostatic
testing
adequate.
"A
more
reasonable
requirement
would
be
to
require
annual
integrity
testing
of
buried
piping.
Further,
a
requirement
that
such
testing
be
anything
other
than
visual
or
hydrostatic
is
financially
burdensome,
and
also
costly
in
terms
of
manpower."
(188,
L18,
L30)

Oil­
handling
piping.
We
should
clarify
that
our
proposed
integrity
and
leak
testing
or
monthly
monitoring
recommendation
applies
only
to
oil­
handling
piping
and
equipment
not
all
buried
piping
or
other
equipment
unrelated
to
oil
operations.
(103)

Recordkeeping.

Opposes
proposal.
We
should
exempt
ASTs
from
the
recordkeeping
requirement.
(65)
It
is
unreasonable
to
require
a
facility
to
keep
records
of
a
recommended
practice
(77).
The
recordkeeping
requirement
is
costly
and
a
significant
administrative
burden.
(90)
The
five­
year
recordkeeping
requirement
is
overly
burdensome
and
unnecessary.
(189)
The
proposed
requirement
is
unmanageable
and
we
failed
to
show
that
it
is
necessary
to
reduce
any
reasonable
risk
of
discharge
to
navigable
waters.
(125)

Supports
proposal.
Supports
the
proposed
requirement
that
an
owner
or
operator
maintain
testing
and
monitoring
records
for
five
years.
(L1)

Separate
document
for
recommendations.
We
should
keep
discretionary
provisions
in
a
separate
guidance
document.
(27)

Response:
Support
for
proposal.
We
appreciate
commenter
support.
269
Buried
piping.
We
have
deleted
the
text
of
the
proposed
recommendation
to
conduct
annual
integrity
and
leak
testing
of
buried
piping
or
monitor
buried
piping
on
a
monthly
basis
from
the
rule
because
we
do
not
wish
to
confuse
the
regulated
public
over
what
is
mandatory
and
what
is
discretionary.
This
rule
contains
only
mandatory
requirements.
However,
we
continue
to
endorse
the
recommendation
as
a
discretionary
action,
and
suggest
that
you
conduct
such
testing
according
to
industry
standards.

We
agree
with
a
commenter
that
the
proposed
recommendation
would
apply
only
to
oilhandling
piping
and
valves,
not
all
such
piping
and
valves,
which
may
be
unrelated
to
oil
activities.
However,
no
change
in
rule
text
is
necessary
because
the
entire
rule
applies
only
to
procedures,
methods,
or
equipment
that
are
involved
with
the
storage
or
use
of
oil.
In
response
to
the
commenter
who
urged
that
the
proposed
recommendation
not
apply
to
buried
piping
of
less
than
10
feet
in
length,
we
believe
that
any
buried
piping,
regardless
of
length,
may
cause
a
discharge,
and
therefore
should
be
tested.
Double­
walled
piping
might
be
an
acceptable
alternative
to
integrity
and
leak
testing
or
monthly
monitoring.
If
you
choose
double­
walled
piping
as
an
alternative,
you
must
explain
your
nonconformance
with
the
rule
requirements,
and
explain
how
double­
walled
piping
provides
equivalent
environmental
protection.
See
112.7(
a)(
2).

On
the
suggestion
of
commenters,
we
have
modified
the
proposed
recommendation
for
annual
testing
or
monthly
monitoring
of
buried
piping
into
a
requirement
that
you
must
only
conduct
integrity
and
leak
testing
of
such
piping
at
the
time
of
installation,
modification,
construction,
relocation,
or
replacement.
We
believe
that
when
piping
is
exposed
for
any
reason,
integrity
and
leak
testing
of
such
exposed
piping
according
to
industry
standards
is
appropriate
because
piping
is
visible
at
that
point,
and
testing
is
easier
because
the
piping
is
more
accessible.
The
same
commenters
also
recommended
that
unprotected
underground
piping
be
subject
to
engineering
evaluations
every
five
years,
but
we
recommend
such
evaluations
be
conducted
in
accordance
with
industry
standards
to
preserve
flexibility
in
case
the
time
frame
changes
with
changing
technology.

Double­
walled
or
vaulted
tanks.
If
you
have
vaulted
containers,
the
requirement
for
integrity
and
leak
testing
of
buried
piping
might
be
the
subject
of
a
deviation
under
§112.7(
a)(
2)
if
those
pipes,
valves,
and
fittings
come
out
of
the
top
of
the
container
and
are
not
buried,
or
are
encased
in
a
double­
walled
piping
system
and
you
thereby
significantly
reduce
the
potential
for
corrosion.

Feedstocks.
We
disagree
that
buried
piping
testing,
whether
annual
or
otherwise,
would
limit
the
facility's
ability
to
receive
feedstocks
and
deliver
finished
products.
The
facility
may
schedule
testing
so
as
not
to
interfere
with
receipt
of
products.

Large
or
small
facilities.
This
requirement
applies
to
facilities
of
any
size
because
the
risk
of
discharge
is
the
same.

Manned
facilities,
aboveground
facilities,
cathodically
protected
facilities.
The
requirement
for
integrity
and
leak
testing
applies
only
to
buried
piping.
Therefore,
aboveground
piping,
whether
manned
or
not,
is
exempted.
Piping
cathodically
270
protected
is
likewise
not
exempt,
but
may
be
the
subject
for
a
deviation
if
you
explain
your
reasons
for
nonconformance,
and
show
that
cathodic
protection
provides
equivalent
environmental
protection
to
the
requirement
to
conduct
integrity
and
leak
testing
of
buried
piping
when
it
is
installed,
modified,
constructed,
relocated,
or
replaced.

Piping
material
or
age.
Good
engineering
practice
would
include
consideration
of
these
factors,
as
well
as
site
conditions.

Coast
Guard
rules.
We
disagree
that
our
rules
should
necessarily
be
consistent
with
Coast
Guard
rules
on
buried
piping
testing.
We
regulate
non­
transportation­
related
facilities.
Comparing
these
facilities
with
transportation­
related
facilities
under
Coast
Guard
programs
is
inappropriate
because
of
the
differences
in
the
types
of
facilities
that
EPA
regulates.

Cost.
We
disagree
integrity
and
leak
testing
is
burdensome
or
costly
for
small
facilities,
or
that
testing
other
than
visual
or
hydrostatic
testing
is
financially
burdensome
and
costly
in
terms
of
manpower.
We
do
not
specify
the
method
of
such
testing.
You
may
use
the
least
costly
method
that
meets
the
requirements
of
the
rule.

Method
of
testing.
We
do
not
require
pressure
testing
or
any
other
specific
method.
While
testing
pursuant
to
standards
following
part
280
or
a
state
program
approved
under
part
281
is
certainly
acceptable,
it
is
not
required.
Generally
we
recommend
testing
according
to
industry
standards.

Guidance.
We
suggest
use
of
industry
standards
where
appropriate.

Recordkeeping.
We
agree
that
a
five
year
period
for
recordkeeping
is
more
than
necessary,
and
instead
require
that
records
be
kept
for
a
maximum
of
three
years.
See
§112.7(
e).
We
disagree
that
ASTs
should
be
exempt
from
the
recordkeeping
requirement.
There
is
no
deviation
for
recordkeeping
if
a
requirement
to
keep
records
is
applicable.
If
the
owner
or
operator
of
a
vaulted
tank
deviates
from
the
requirement
to
test
buried
piping
at
the
specified
intervals,
he
must
explain
his
reasons
for
nonconformance,
and
provide
equivalent
environmental
protection.
If
the
equivalent
environmental
protection
provided
requires
tests
or
inspections,
records
of
those
tests
or
inspections
must
be
maintained
for
three
years.

XI
­
C(
4)
Vehicular
traffic
­
§112.8(
d)(
5)

Background:
Section
112.7(
e)(
3)(
v)
of
the
current
rule
requires
warning
verbally
or
by
appropriate
signs
for
vehicular
traffic
granted
entry
into
the
facility
to
be
sure
that
the
vehicle,
because
of
its
size,
will
not
endanger
aboveground
piping.
In
1991,
we
proposed
to
redesignate
the
provision
as
§112.8(
d)(
5),
adding
a
recommendation
that
the
owner
or
operator
post
weight
restrictions,
as
applicable,
to
prevent
damage
to
underground
piping.
271
Comments:
Support
for
proposal.
"It
seems
that
good
engineering
practices
would
exclude
heavy
equipment
from
crossing
buried
piping
which
does
not
have
adequate
cover
to
protect
the
pipe."
(39,
48,
51,
53,
72,
102,
143,
147,
161,
168,
L8).

Alternatives.

Additional
structural
protection.
"MDE
recommends
that
if
a
buried
pipe
must
be
placed
across
a
thoroughfare,
it
should
be
installed
with
additional
structural
protection.
Proper
installation
is
preventative
and
is
a
better
alternative
over
a
sign.
The
vehicle
weight
restriction
signs
are
not
always
needed."
(135)

Local
building
codes.
"In
virtually
all
cases,
local
building
codes
or
other
standards
already
address
the
issue
of
buried
piping
protection."
(53)

Location
and
marking.
"This
could
result
in
weight
limits
being
set
low
at
some
sites
that
access
would
be
denied
to
the
very
vehicles
which
need
access
to
make
the
facility
economically
viable
­
and
which
have
driven
over
the
same
piping
for
a
dozen
or
more
years.
...
Location
and
marking
of
such
piping
so
that
it
could
be
temporarily
protected,
or
avoided,
would
appear
to
be
an
acceptable
alternate.
While
it
could
be
argued
that
providing
such
protection
or
rerouting
emergency
equipment
is
not
practical,
it
is
at
least
as
practical
as
expecting
such
equipment
to
comply
with
weight
restriction
signs!"
(76)

PE
discretion.
"This
provision
recommends
the
posting
of
vehicle
weight
restrictions.
However,
it
would
be
preferable
for
EPA
to
require
that
a
PE
be
involved
in
evaluating
this
question
and
that
the
PE's
conclusions
be
documented
and
implemented."
(43)

Requirement,
not
recommendation.
The
rule
"should
require,
rather
than
recommend,
that
vehicular
weight
restrictions
be
posted
to
prevent
damage
to
underground
piping."
(44,
52)

Rerouting.
"Location
and
marking
of
such
piping
so
that
it
could
be
temporarily
protected,
or
avoided,
would
appear
to
be
an
acceptable
alternate.
While
it
could
be
argued
that
providing
such
protection
or
rerouting
emergency
equipment
is
not
practical,
it
is
at
least
as
practical
as
expecting
such
equipment
to
comply
with
weight
restriction
signs!"
(76)

Applicability.

Airports.
The
proposal
is
"unreasonable
at
airport
facilities
where
some
buried
piping/
hydrant
systems
run
under
ramp
surfaces.
Posting
of
signs
in
such
open
areas
would
be
impractical
and
impact
operations."
(107)
272
Large
facilities.
Recommendation
should
apply
only
"to
large
facilities
because
only
large
facilities
will
have
the
type
of
tanker
trucks
which
would
potentially
damage
underground
piping."
(34,
75,
182)

Railroads.
"This
recommendation
is
overly
broad.
Railroads
have
a
large
amount
of
piping
under
track
that
is
built
to
withstand
maximum
loads
from
vehicular
traffic.
It
is
unnecessary
to
require
signs
for
such
pipes.
Furthermore,
it
would
be
costly
to
post
signs
wherever
there
is
underground
piping
on
railroad
property."
(57)

Vaulted
tanks.
"Because
VAST
technology
requires
all
openings
and
fittings
to
be
placed
at
the
top
of
the
tank,
and
requires
the
dike
in
the
form
of
a
concrete
vault
to
immediately
encompass
the
secondary
containment,
the
risk
of
damage
from
vehicular
traffic
has
been
significantly
reduced,
making
the
provisions
in
§112.8(
d)(
5)
unduly
burdensome
and
costly
to
sites
using
VAST
technology."
(65)

Costs.
We
failed
to
recognize
the
substantial
costs
to
owners
or
operators
of
determining
accurate
weight
restrictions.
(76)

Guidance.
"...(
U)
nless
further
guidance
is
provided
on
the
method
of
determining
an
acceptable
weight
limit,
this
item
should
be
eliminated."
(169)

Response:
Support
for
proposal.
We
appreciate
commenter
support.

Applicability.
The
requirement
to
warn
vehicular
traffic
so
that
no
vehicle
will
endanger
aboveground
piping
or
other
oil
transfer
operations
applies
to
all
facilities,
large
or
small,
because
vehicular
traffic
may
endanger
aboveground
piping
or
other
transfer
operations
at
all
facilities.
Warnings
may
include
verbal
warnings,
signs,
or
marking
and
temporary
protection
of
piping
or
equipment.
No
particular
height
restriction
is
incorporated
into
the
rule.
Rather,
aboveground
piping
at
any
height
must
be
protected
from
vehicular
traffic
unless
the
piping
is
so
high
that
all
vehicular
traffic
passes
underneath
the
piping.
In
this
case,
or
where
the
requirement
is
infeasible,
you
may
be
able
to
use
the
deviation
provision
in
§112.7(
a)(
2)
if
you
explain
your
reasons
for
nonconformance
and
provide
equivalent
environmental
protection.
We
have
deleted
the
clause
concerning
the
size
of
vehicles
that
may
endanger
piping
or
oil
transfer
operations
because
the
owner
or
operator
may
not
be
able
to
determine
precisely
when
the
size
or
weight
of
a
vehicle
which
would
cause
such
endangerment.

In
response
to
commenters
who
suggested
that
the
posting
of
signs
is
impractical
and
might
impact
operations,
or
would
be
very
costly,
we
note
that
you
may
deviate
from
the
requirement
under
§112.7(
a)(
2)
if
you
explain
your
reasons
for
nonconformance
and
provide
equivalent
environmental
protection.

Costs.
Even
though
we
did
not
include
the
recommendation
in
the
final
rule,
we
included
the
estimated
costs
of
the
proposal
in
our
1991
economic
analysis.
273
New
regulatory
structure.
We
see
no
need
for
a
new
regulatory
structure
because
buried
piping
is
likely
to
be
an
appurtenance
to
a
completely
buried
tank
and
as
such,
is
likely
to
be
regulated
under
40
CFR
part
280.
If
the
piping
is
not
of
a
completely
buried
tank,
the
appurtenance
is
likely
covered
by
part
112
requirements.
Therefore,
a
new
regulatory
structure
is
unnecessary.

Weight
restriction
posting.
We
deleted
the
proposed
recommendation
concerning
weight
restrictions
as
it
relates
to
underground
piping
from
rule
text,
but
still
support
it
when
appropriate.
We
include
only
mandatory
items
in
this
rule
because
we
do
not
wish
to
confuse
the
regulated
public
as
to
what
is
mandatory
and
what
is
discretionary.
We
decline
to
make
the
recommendation
a
requirement
because
we
believe
the
appropriate
posting
of
weight
restrictions
should
be
a
matter
of
good
engineering
practice.
274
Category
XII:
Onshore
production
facility
Plan
requirements
XII
­
A:
Production
facilities
(general
requirements)
­
§112.9(
a)

Background:
In
1991,
we
proposed
to
reorganize
§112.7(
e)
of
the
current
rule
into
four
sections
(§§
112.
8,
112.
9,
112.
10,
and
112.
11),
based
on
facility
type.
We
proposed
§112.7(
e)(
5)
of
the
current
rule
as
§112.9
in
1991.

Comments:
Cost.
Section
§112.9
of
the
proposed
rule
would
result
in
an
increased
economic
burden
on
owners
or
operators
of
production
facilities
–
particularly
small
facilities
with
"stripper"
wells.
"For
these
wells,
any
substantial
capital
expense
or
increase
in
operating
costs
will
very
likely
result
in
premature
closure."
(42,
67,
91,
101)

Performance
standards.
"Arbitrary
standards
for
onshore
and
offshore
production
facilities
(40
CFR
§§
112.
9
and
112.
11)
should
be
deleted
and
replaced
by
reasonable
performance
standards."
(86)

Reorganization
of
rule.
"The
requirements
for
oil
production
facilities
should
be
consolidated
with
similar
requirements
for
on­
shore
facilities.
The
few
differences
between
the
two
types
of
facilities
could
be
handled
on
a
call­
out
basis.
As
§§
112.8
and
112.9
are
now
written,
they
are
similar
but
not
identical.
There
appears
to
be
no
justification
for
the
difference."
(111)

Response:
Cost.
EPA
considered
cost
factors
in
finalizing
the
requirements
in
this
rule.
We
believe
that
facilities
in
compliance
with
the
current
rule
will
incur
minimal
additional
cost
due
to
the
revisions
in
this
rule.
Many
of
the
provisions
we
proposed
in
1991
that
commenters
believed
were
too
costly
were
not
finalized
in
the
rule,
In
addition,
in
today's
rule,
we
have
provided
flexibility
in
several
ways.
Furthermore,
we
are
finalizing
other
provisions
in
this
rule
which
will
reduce
burden
in
other
ways
and
will
exempt
certain
facilities
from
having
to
prepare
a
Plan.
EPA
has
also
prepared
an
assessment
of
the
costs
of
rule
compliance,
which
is
discussed
in
part
VI.
F
(Regulatory
Flexibility
Act)
of
today's
preamble,
and
we
have
included
the
specific
comments
related
to
costs
and
our
responses
in
relevant
sections
of
this
preamble.

We
agree
that
we
should
require
performance
standards
in
this
regulation
rather
than
prescriptive
standards.
Throughout
the
rule
we
generally
allow
for
the
application
of
industry
standards
where
the
standards
are
both
specific
and
objective,
and
their
application
may
reduce
the
risk
of
discharges
to
and
impacts
to
the
environment.
We
also
permit
the
owner
or
operator
greater
flexibility
by
allowing
the
use
of
deviations
under
either
§112.7(
a)(
2)
or
(d).

Performance
standards.
The
final
rule
generally
provides
for
use
of
performance
standards
rather
than
design
standards.
See
§§
112.7(
a)(
2)
and
(d).

Reorganization
of
rule.
We
generally
agree
that
the
current
rule
is
adequate
and
effective
in
preventing
discharges.
We
have
reorganized
the
rule
into
subparts
and
sections
based
275
on
the
type
of
oil
stored
or
used
and
the
type
of
facility
for
clarity
and
ease
of
use.
The
reorganization
is
not
a
substantive
change.

XII
­
B:
Facility
drainage
­
§112.9(
b)
(proposed
as
§112.9(
c))

XII
­
B(
1)
Diked
storage
area
drainage
­
§112.9(
b)(
1)

Comments:
Applicability.
Urges
a
small
facility
exemption
from
this
requirement
because
the
recordkeeping
involved
was
too
burdensome.

Editorial
changes
and
clarifications.
"The
language
in
§112.9(
c)(
1)
stating
`...
where
an
accidental
discharge
of
oil
would
have
a
reasonable
possibility
of
reaching
navigable
waters....
'
does
not
agree
with
the
wording
in
§112.1(
b)(
1)
stating
`...
which
due
to
their
location
could
reasonably
be
expected
to
discharge
oil
in
quantities
that
may
be
harmful....
'
These
sections
should
be
made
consistent."
(154)
"The
requirement
to
have
all
drains
closed
on
dikes
around
storage
tanks
might
preclude
engineering
measures
(stand
pipes)
designed
to
handle
flow­
through
conditions
at
water
flood
oil
production
operations,
where
large
volumes
of
water
may
be
directed
to
oil
storage
tanks
if
water
discharge
lines
on
oil­
water
separators
become
plugged."
(28,
31,
101,
165)

Recordkeeping.
The
recordkeeping
provisions
in
proposed
§112.9(
c)(
1)
are
overly
burdensome
and
of
little
benefit.
(28,
58)

Small
facilities.
We
should
exclude
small
facilities
from
the
recordkeeping
requirements.
(58)

Response:
Applicability.
We
believe
that
this
requirement
must
be
applicable
to
both
large
and
small
facilities
to
help
prevent
discharges
as
described
in
§112.
1(
b).
The
risk
of
such
a
discharge
and
the
accompanying
environmental
damage
may
be
harmful
whether
it
comes
from
a
large
or
small
facility.
We
disagree
that
the
recordkeeping
is
burdensome.
If
you
are
an
NPDES
permittee,
you
may
use
the
stormwater
drainage
records
required
pursuant
to
40
CFR
122.41(
j)(
2)
and
122.41(
m)(
3)
for
SPCC
purposes,
thereby
reducing
the
recordkeeping
burden.

Editorial
changes
and
clarifications.
In
response
to
the
commenter's
suggestion,
the
reference
to
"navigable
waters"
becomes
a
reference
to
"a
discharge
as
described
in
§112.1(
b)."
"Central
treating
stations"
becomes
"separation
and
treating
areas."
Such
areas
might
be
centrally
located
or
located
elsewhere
at
the
facility
and
might
include
both
separation
and
treatment
devices
and
equipment.
The
reference
to
"rainwater
is
being
drained"
becomes
"draining
uncontaminated
rainwater."
We
clarify
that
accumulated
oil
on
rainwater
must
be
disposed
of
in
accord
with
"legally
approved
methods,"
not
"approved
methods."

Alternatives.
We
should
modify
proposed
§112.9(
c)(
1),
allowing
owners
or
operators
to
recycle
accumulated
oil
on
the
rainwater
by
other
methods.
This
modification
would
allow
flexibility
to
seek
alternate,
environmentally
sound
recycling
methods.
(L12)
276
Engineering
methods.
"Equivalent"
measures
referenced
in
the
rule
might,
depending
on
good
engineering
practice,
include
using
structures
such
as
stand
pipes
designed
to
handle
flow­
through
conditions
at
water
flood
oil
production
operations,
where
large
volumes
of
water
may
be
directed
to
oil
storage
tanks
if
water
discharge
lines
on
oil­
water
separators
become
plugged.
Any
alternate
measures
must
provide
environmental
protection
equivalent
to
the
rule
requirement.

Industry
standards.
Industry
standards
that
may
assist
an
owner
or
operator
with
facility
drainage
include
API
Recommended
Practice
51,
"Onshore
and
Oil
and
Gas
Production
Practices
for
Protection
of
the
Environment."

Recordkeeping.
We
agree
that
a
five­
year
record
retention
period
is
longer
than
necessary
and
have
deleted
the
proposed
requirement
in
favor
of
the
general
requirement
in
§112.7(
e)
to
maintain
records
for
three
years.
However,
this
requirement
must
apply
to
both
large
and
small
facilities
to
help
prevent
discharges
as
described
in
§112.
1(
b).
The
risk
of
such
a
discharge
and
the
accompanying
environmental
damage
from
a
small
facility
may
be
as
harmful
as
from
a
large
facility.
If
you
keep
stormwater
drainage
records
required
pursuant
to
40
CFR
122.41(
j)(
2)
and
122.41(
m)(
3),
you
may
use
such
records
for
SPCC
purposes,
thereby
reducing
the
recordkeeping
burden.

XII
­
B(
2):
Drainage
ditches,
accumulations
of
oil
­
§112.9(
b)(
2)
(proposed
as
§112.9(
c)(
2))

Background:
Under
§112.7(
e)(
5)(
ii)(
B)
of
the
current
rule,
an
owner
or
operator
of
an
onshore
production
facility
must
inspect
and
remove
accumulations
of
oil
from
field
drainage
ditches,
oil
traps,
sumps,
or
skimmers.
In
1991,
we
proposed
to
redesignate
§112.7(
e)(
5)(
ii)(
B)
as
§112.9(
c)(
2),
and
to
require
the
owner
or
operator
to
remove
oilcontaminated
soils
as
well
as
accumulated
oil
within
72
hours,
if
immediate
removal
was
not
feasible.
We
solicited
comments
on
the
appropriate
amount
of
time
for
discovery
and
removal
of
accumulated
oil,
recognizing
that
production
facilities
may
not
be
staffed
during
a
given
72­
hour
period.

Comments:
Authority.
EPA
lacks
CWA
authority
for
this
provision.
CWA
addresses
clean
water,
not
"clean
dirt."
(28,
58)

Clarifications
­
"accumulation,"
"oil­
contaminated
soil."
We
should
clarify
the
terms
accumulation
and
oil­
contaminated
soil
in
the
context
of
the
proposed
requirement
to
remove
accumulated
oil
or
oil­
contaminated
materials
within
72
hours.
(28,
58,
71,
101,
153)

Inspection
schedule.
"Field
drainage
ditches,
etc.,
should
have
a
schedule
set
for
inspection
of
accumulations
of
oil.
OHIO
EPA
recommends
monthly
inspections,
and
within
24­
hours
of
a
25­
year
storm
event."
(27)
277
72­
hour
cleanup
standard.

Opposition
to
proposal.

Bioremediation.
"Accumulated
oil
should
be
picked
up
and
properly
hauled.
However,
problems
associated
with
oil­
contaminated
soil
can
often
be
addressed
as
well
or
better
if
the
material
is
left
in
place.
Bioremediation
techniques
and
other
measures
which
may
be
used
under
existing
laws
are
less
expensive
and
create
less
waste
than
removal
procedures."
Proposal
may
limit
bioremediation
or
other
cleanup
techniques.
Clean
up
should
be
allowed
in
accordance
with
State
and
local
requirements.
(31,
67,
86,
90,
91,
99,
101,
144,145,
160,
167,
173)

Costly.
"Landfill
space
is
at
a
premium
and
on­
site
bioremediation
has
the
potential
to
prevent
environmental
harm
in
a
more
cost
effective
manner
with
equivalent
environmental
results."
(99,
101,
160)

Impractical
or
impossible.
"In
addition,
the
72­
hour
requirement
is
unreasonable
in
many
instances.
In
cases
where
a
significant
amount
of
oil
has
been
released,
or
in
remote
locations,
where
it
may
be
difficult
to
mobilize
the
equipment
needed,
or
in
snowy
areas
where
leaks
cannot
be
easily
observed,
it
may
be
virtually
impossible
to
complete
cleanup
within
72
hours."
(31,
67,
71,
86,
91,
101,
153,
160,
167,
173,
175,
187,
L12,
L18)
An
owner
or
operator
may
be
unable
to
obtain
proper
regulatory
authorization
to
remove
and
dispose
of
oil­
contaminated
soil
within
72
hours.
(31,
86,
153)
Removal
within
72
hours
from
the
time
of
the
spill
would
be
difficult
at
an
unattended
facility.
(102)
Frequently,
it
is
technically
infeasible
to
remove
contaminated
soil
because
of
"structural
concerns"
or
the
volume
of
soil.
(153,
173)
Some
facilities
have
oil­
contaminated
soil
from
past
spills.
(162)

Landfill
disposal
problems.
The
requirement
to
remove
all
oil­
contaminated
soil
could
compound
landfill
disposal
capacity
problems.
(99,
165,
L15)

Navigable
waters.
We
should
require
the
owner
or
operator
to
remove
the
accumulation
of
oil
only
if
that
oil
might
reach
navigable
waters.
(L12)

Safety
or
health
problems.
The
72­
hour
requirement
could
pose
a
safety
or
health
hazard
to
employees.
(102)

Unnecessary.
The
72­
hour
requirement
would
be
excessive
and
unnecessary
because
spill
response
procedures
already
must
be
described
in
the
SPCC
Plan.
(31,
86)
It
is
unnecessary
to
remove
all
spilled
oil
within
72
hours
if
the
containment
system
is
designed
to
be
impervious
to
oil
for
a
longer
period
of
time.
(71)
278
Time
calculations.

Discovery.
Since
the
time
when
the
spill
occurred
may
be
unknown,
any
time
frame
for
removing
oil
or
oil­
contaminated
materials
should
be
based
on
when
the
spill
is
discovered.
(67,
71,
91,
102,
133,
153,
167,
173)

72­
hour
cleanup
standard
­
suggested
alternatives.

As
soon
as
practical.
We
should
require
that
the
owner
or
operator
complete
clean­
up
operations
"as
soon
as
practical"
or
"within
a
timely
manner,"
or
"after
the
spill
is
discovered."
(78,
101,
102,
133,
153,
167,
173,
187)

Immediately
upon
discovery.
We
should
revise
the
proposal
to
require
that
cleanup
operations
begin
immediately
upon
discovery
of
a
spill,
and
that
every
reasonable
effort
be
made
to
complete
the
clean­
up
within
72
hours.
(153)

Initiation
within
72
hours.
We
should
require
the
initiation
of
remedial
activities
to
begin
within
72
hours
from
when
the
spill
occurred.
(18)

Precautions.
"During
remediation
operations,
precautions
are
taken
to
prevent
contamination
of
surface
water
by
stormwater
runoff.
A
dike
or
ditch
may
be
constructed
around
the
area,
or
oil
absorbent
materials
may
be
placed
around
the
area.
Covering
with
plastic
film
is
another
acceptable
means
to
temporarily
prevent
stormwater
contamination
during
remediation
operations."
(99)

Response:
Authority.
We
have
adequate
authority
to
require
cleanup
of
an
accumulation
of
oil,
including
on
soil
and
other
materials,
because
section
311(
j)(
1)(
C)
of
the
CWA
provides
EPA
with
the
authority
to
establish
procedures,
methods,
and
equipment
and
other
requirements
for
equipment
to
prevent
discharges
of
oil.
The
broad
definition
of
"oil"
under
CWA
section
311(
a)(
1)
covers
"oil
refuse"
and
"oil
mixed
with
wastes
other
than
dredged
spoil."
If
field
drainage
systems
allow
the
accumulation
of
oil
on
the
soil
or
other
materials
at
the
onshore
facility
and
that
oil
threatens
navigable
water
or
adjoining
shorelines,
then
EPA
has
authority
to
establish
a
method
or
procedure,
i.
e.,
the
removal
of
oil
contaminated
soil,
to
prevent
that
oil
from
becoming
a
discharge
as
described
in
§112.1(
b).
The
cleanup
standard
under
this
paragraph
requires
the
complete
removal
of
the
contaminated
oil,
soil,
or
other
materials,
either
by
removal,
or
by
bioremediation,
or
in
any
other
effective,
environmentally
sound
manner.

Clarifications
­
"accumulation,"
"oil­
contaminated
soil."

Accumulation.
We
retain
the
term
"accumulation
of
oil,"
but
elaborate
on
its
meaning.
"Accumulation
of
oil"
means
a
discharge
that
causes
a
"film
or
sheen"
within
the
field
drainage
system,
or
causes
a
sludge
or
emulsion
there
(see
40
CFR
110.3(
b)).
An
accumulation
of
oil
includes
anything
on
which
the
oil
gathers
or
amasses
within
the
field
drainage
system.
An
accumulation
of
oil
may
include
oilcontaminated
soil
or
any
other
oil­
contaminated
material
within
the
field
drainage
279
system.
See
also
the
discussion
of
"accumulation
of
oil"
included
with
the
response
to
comments
of
§112.8(
c)(
10).

Oil­
contaminated
soil.
We
eliminated
the
term
"oil­
contaminated
soil"
because
oil
must
accumulate
on
something,
such
as
materials
or
soil.

Inspection
schedule.
We
have
retained
the
"regularly
scheduled
intervals"
standard
for
inspections.
This
standard
means
regular
inspections
according
to
industry
standards
or
on
a
schedule
sufficient
to
prevent
a
discharge
as
described
in
§112.1(
b).
Whatever
schedule
for
inspections
is
selected
must
be
documented
in
the
Plan.
We
decline
to
specify
a
specific
interval
because
such
an
interval
might
become
obsolete
with
changing
technology.

72­
hour
cleanup
standard.
We
agree
that
the
72­
hour
cleanup
standard
might
preclude
bioremediation
and
have
therefore
deleted
it.
Instead
we
establish
a
standard
of
"prompt
cleanup."
"Prompt"
cleanup
means
beginning
the
cleanup
immediately
after
discovery
of
the
discharge
or
immediately
after
any
actions
necessary
to
prevent
fire
or
explosion
or
other
imminent
threats
to
worker
health
and
safety.

Precautions.
We
note
that
an
owner
or
operator
may
choose
to
spread
plastic
film
over
the
diked
area
to
prevent
the
occurrence
of
an
accumulation
of
oil.
However,
he
must
dispose
of
the
film
properly.

XII
­
C:
FEMA
requirements
­
proposed
§112.9(
c)(
3)

Comments
for
this
section
are
addressed
in
Subcategory
XVI­
B:
State
programs,
SARA
Title
III,
wellhead
protection,
flood­
related
requirements,
OSHA,
and
industry
standards.

XII
­
D:
Production
facilities
­
bulk
storage
containers
­
§112.9(
c)
(proposed
§112.9(
d))

XII
­
D(
1)
Material
and
construction
­
§112.9(
c)(
1)

Background:
Section
112.7(
e)(
5)(
iii)(
A)
of
the
current
rule
provides
that
for
an
onshore
production
facility,
tanks
should
not
be
used
for
storing
oil
unless
the
tank
material
and
construction
are
compatible
with
the
material
stored
and
the
storage
conditions.
In
1991,
we
proposed
to
redesignate
the
current
rule
provision
as
§112.9(
d)(
1),
and
to
recommend
that
tank
construction
and
operation
conform
to
relevant
industry
standards
because
applying
these
standards
reflects
good
engineering
practice.

Comments:
Local
standards.
"OOGA
seeks
clarification
that
USEPA
recognizes
that
local
standards
sometimes
control
industry
standards
on
certain
issues
and
that
such
could
occur
under
this
provision."
(58)

Recommendation
v.
requirement.
`Proposed
section
112.9(
d)
should
require,
rather
than
recommend,
that
tanks
meet
industry
standards.
At
a
date
certain,
all
existing
tanks
280
should
be
upgraded
to
meet
industry
standards.
Moreover,
all
new
and
reconstructed
tanks
should
be
subject
to
applicable
codes."
(44)

Response:
Recommendation
v.
requirement.
We
are
retaining
the
mandatory
requirement
to
use
no
container
for
the
storage
of
oil
unless
its
material
and
construction
are
compatible
with
the
material
stored
and
the
conditions
of
storage,
as
proposed.
We
have
deleted
the
recommendation
that
materials,
installation,
and
use
of
new
tanks
conform
with
relevant
portions
of
industry
standards
because
we
do
not
wish
to
confuse
the
regulated
public
over
what
is
mandatory
and
what
is
discretionary.
However,
we
endorse
its
substance.
In
most
cases
good
engineering
practice
and
liability
concerns
will
prompt
the
use
of
industry
standards.
See
§112.3(
d)(
1)(
iii).
In
addition,
a
requirement
is
not
necessary
or
desirable
because
local
governmental
standards
on
construction,
materials,
and
installation
sometimes
control
industry
standards
on
these
matters.

XII
­
D(
2)
Secondary
containment
­
§112.9(
c)(
2)

Background:
In
1991,
we
proposed
in
§112.9(
d)(
2)
(redesignated
as
§112.9(
c)(
2)
in
the
final
rule)
(§
112.7(
e)(
5)(
iii)(
B)
of
the
current
rule)
to
clarify
that
required
secondary
containment
must
include
sufficient
freeboard
for
precipitation.
We
also
reproposed
the
requirement
to
confine
drainage
from
undiked
areas.

Comments:
Applicability.

Oil
leases.
The
proposal
is
"is
too
vague
and
comprehensive
to
be
applied
to
oil
leases.
It
would
be
applicable
to
entire
leases
covering
hundreds
of
acres
if
interpreted
improperly."
(31,
101,
165,
L15)

Clarification.

Accumulation.
"Is
accumulated
oil
and
contaminated
soil
to
be
removed
from
diked
areas
under
this
provision?
What
is
contaminated
soil?
What
are
the
cleanup
standards
under
this
provision?
What
is
an
`accumulation'."
(58)

Methods.
We
should
not
allow
alternate
secondary
containment
systems
such
as
those
outlined
in
§112.7(
c)(
1)
of
this
part.
(121)

NPDES
rules.
"The
new
EPA
NPDES
storm
water
program
clearly
and
very
thoroughly
regulates
potential
precipitation­
drainage
related
pollution
from
these
sources.
The
requirements
in
this
sentence
amount
to
a
duplicative
regulatory
requirement
by
the
same
agency."
(28,
101,
L12)

Sufficient
freeboard.
We
do
not
set
a
standard
for
"sufficient"
freeboard.
The
owner,
operator,
or
Professional
Engineer
(PE)
should
be
able
to
determine
the
appropriate
size
for
secondary
containment
on
a
site­
by­
site
basis.
(75)
281
Response:
Applicability.
The
requirement
applies
to
oil
leases
of
any
size.
Secondary
containment
is
not
required
for
the
entire
leased
area,
merely
for
the
contents
of
the
largest
single
container
in
the
tank
battery,
separation,
and
treating
facility
installation,
with
sufficient
freeboard
to
contain
precipitation.

Clarification.

Accumulation.
We
retain
the
term
"accumulation
of
oil,"
but
elaborate
on
its
meaning.
"Accumulation
of
oil"
means
a
discharge
that
causes
a
"film
or
sheen"
within
the
field
drainage
system,
or
causes
a
sludge
or
emulsion
there
(see
40
CFR
110.3(
b)).
An
accumulation
of
oil
includes
anything
on
which
the
oil
gathers
or
amasses
within
the
field
drainage
system.
An
accumulation
of
oil
may
include
oilcontaminated
soil
or
any
other
oil­
contaminated
material
within
the
field
drainage
system.
See
also
the
discussion
of
"accumulation
of
oil"
included
with
the
response
to
comments
of
§112.8(
c)(
10).

Methods.
We
disagree
that
we
should
not
allow
alternate
secondary
containment
systems
such
as
those
in
§112.7(
c)(
1).
We
note
that
no
single
design
or
operational
standard
is
appropriate
for
all
onshore
production
facilities.
An
owner
or
operator
must
choose
the
appropriate
secondary
containment
system
compatible
with
good
engineering
practice.

NPDES
rules.
We
deleted
the
proposed
reference
to
undiked
areas
"showing
a
potential
for
contamination"
because
drainage
from
any
undiked
area
poses
a
threat
of
contamination.
When
drainage
from
such
areas
is
covered
by
storm
water
discharge
permits,
that
part
of
the
BMP
might
be
usable
for
SPCC
purposes.
There
is
no
redundancy
in
recordkeeping
requirements,
because
you
can
use
your
NPDES
records
for
SPCC
purposes.

Sufficient
freeboard.
In
response
to
the
comment
as
to
how
an
owner
or
operator
might
determine
how
much
freeboard
is
sufficient,
we
have
revised
the
rule
to
provide
that
freeboard
sufficient
to
contain
precipitation
is
the
standard.
We
have
recommended
a
standard
for
sufficient
freeboard
in
the
final
rule.
That
standard
is
sufficient
freeboard
to
contain
a
25­
year,
24­
hour
storm
event.
However,
because
of
the
difficulty
and
cost
of
securing
recent
information
concerning
such
events,
we
are
not
making
this
a
rule
standard.

XII
­
D(
3):
Container
inspection
­
§112.9(
c)(
3)

Background:
Section
112.7(
e)(
5)(
iii)(
C)
of
the
current
rule
provides
that
production
tanks
must
be
visually
inspected
on
a
periodic
schedule
and
the
foundation
and
supports
of
aboveground
tanks
must
be
inspected
for
deterioration.
In
1991,
we
proposed
to
designate
§112.7(
e)(
5)(
iii)(
C)
as
§112.9(
d)(
3)
(redesignated
as
§112.9(
c)(
3)
in
the
final
rule)
and
to
require
tank
examinations
at
least
once
a
year.
We
also
proposed
that
an
owner
or
operator
keep
schedules
and
records
of
examinations
for
the
last
five
years,
regardless
of
change
in
ownership.
282
Comments:
Extent
of
inspection.

Visual
inspections.
"It
is
not
practicable
to
internally
visually
examine
tanks
on
an
annual
basis
due
to
the
number
that
would
need
to
be
taken
out
of
service
at
any
one
time
to
meet
the
requirement.
API
agrees
with
scheduled
visual
external
examinations
of
tanks
but
believes
that
internal
examinations
and
inspections
should
be
accomplished
in
accordance
with
API
Recommended
Practice
12R1."
(67,
85,
167)

Frequency
of
inspection.

Support
for
proposal.
"Ohio
EPA
agrees
with
the
provision
for
annual
inspections
of
tank
batteries,
and
with
the
requirement
to
keep
the
record
of
inspection
for
five
years."
(27)

More
frequent
inspections.
We
should
direct
owners
or
operators
to
examine
production
tanks
quarterly.
(121)

Opposition
to
proposal.
"Requiring
an
annual
tank
inspection
and
record
maintenance
is
an
unnecessary
expense.
"
(101)

"If
possible."
We
should
require
examining
a
tank's
aboveground
foundation
and
supports
only
"if
practical"
or
"if
possible."
An
owner
or
operator
might
be
unable
to
inspect
a
tank
where
the
foundation
settled
or
there
is
a
lack
of
space.
(67,
173)

Triennial
inspection.
Documenting
an
annual
inspection
would
increase
paperwork
with
no
benefit
to
small
facilities.
The
existing
provision
is
adequate.
"More
importantly,
the
three
year
review
of
the
SPCC
Plan
pursuant
to
section
112.5(
b)
is
more
than
sufficient
to
document
a
visual
inspection
of
the
facilities."
(58,
70)

Record
maintenance.

Opposition
to
proposal.
"OOGA
is
uncertain
of
the
recordkeeping
requirement
under
this
provision.
Undeniably,
owners
of
crude
oil
production
facilities
routinely
inspect
their
storage
tanks.
To
document
these
inspections
seems
to
serve
no
useful
purpose."
(58,
70)
"The
agency
does
not
indicate
a
reason
for
increasing
the
records­
retention
requirement
from
three
to
five
years.
Most
if
not
all
CWA
related
programs
have
a
mandatory
three­
year
records
retention
requirement.
EPA
needs
to
explain
their
reason(
s)
for
the
more
costly
five­
year
mandatory
requirement.
This
request
is
made
for
every
EPA
mandatory
five­
year
record
retention
requirement
in
this
proposed
rule."
(L12)

PE
Certification.
"Regular
inspections
and
record
maintenance
provisions
should
not
require
the
certification
of
a
Registered
Professional
Engineer,
which
is
one
possible
interpretation
of
these
requirements,
as
records
are
included
in
the
Plan."
(101,
165,
L15)
283
Phase­
in.
The
rule
should
provide
for
a
two­
year
phase­
in
period
so
that
the
facility
will
have
the
required
five
years
of
records.
(102)

Response:
Extent
of
inspection.
We
disagree
that
the
inspection
of
containers
should
be
limited
to
external
inspection.
Internal
inspection
is
also
necessary
to
detect
possible
flaws
that
could
cause
a
discharge.
The
inspection
must
also
include
foundations
and
supports
that
are
on
or
above
the
surface
of
the
ground.
If
for
some
reason
it
is
not
practicable
to
inspect
the
foundations
and
supports,
you
may
deviate
from
the
requirement
under
§112.7(
a)(
2),
if
you
explain
your
rationale
for
nonconformance
and
provide
equivalent
environmental
protection.

API
standards.
Regarding
the
comment
that
we
should
require
internal
examinations
and
inspections
in
accordance
with
an
API
practice,
we
note
that
while
API
standards
may
be
sufficient
for
many
facilities,
no
single
design
or
operational
standard
is
appropriate
for
all
non­
transportation­
related
facilities.
An
owner
or
operator
should
choose
the
appropriate
standard
in
the
exercise
of
good
engineering
practice.

Visual
inspection.
Visual
examinations
must
be
in
accordance
with
§112.9(
c)(
3)
specifications,
and
must
include
the
foundations
and
support
of
each
container.

Frequency
of
inspection.
We
have
maintained
the
current
standard
for
frequency
of
inspection
because
we
agree
that
inspections
in
accordance
with
industry
standards
are
necessary.
Those
standards
may
change
with
changing
technology,
therefore,
a
frequency
of
"periodically
and
upon
a
regular
schedule"
preserves
maximum
flexibility
and
upholds
statutory
intent.

Owner/
operator
discretion.
We
decline
to
give
an
owner
or
operator
absolute
discretion
to
inspect
if
practical
or
possible;
instead
we
recommend
inspection
according
to
industry
standards.
Whatever
frequency
of
inspection
that
is
chosen
must
be
noted
in
the
Plan.

Record
maintenance.
Recordkeeping
is
necessary
to
document
compliance
with
the
rule.
We
have
deleted
the
proposed
requirement
to
maintain
records
of
these
inspections
for
five
years,
irrespective
of
ownership,
because
it
is
redundant
with
the
general
requirement
in
§112.7(
e)
to
maintain
Plan
records.
Section
112.7(
e)
requires
record
maintenance
for
three
years.
However,
you
should
note
that
certain
industry
standards
(for
example,
API
Standard
653
or
API
Recommended
Practice
12R1)
may
specify
that
an
owner
or
operator
maintain
records
for
longer
than
three
years.

PE
Certification.
We
do
not
require
a
PE
to
certify
inspection
records
because
such
records
are
not
part
of
the
Plan.

XX
­
D(
4)
Good
engineering
practice
­
tank
batteries
­
§112.9(
c)(
4)
284
Comments:
Good
engineering
practice.
"Proposed
section
112.9(
d)(
4)
should
contain
a
requirement
for
fail­
safe
engineering
of
oil
production
facility
tanks,
just
as
onshore
bulk
storage
is
required
to
be
fail­
safe
engineered
(see
proposed
section
112.8(
c)(
8)),
to
avoid
confusion
among
the
regulated
community
and
to
improve
spill
prevention."
(27,
44)

Small
facilities.
"Single
tanks
with
a
capacity
of
10,
000
gallons
or
less
and
facilities
with
a
capacity
of
40,000
gallons
or
less
should
be
exempt
from
this
section."
(28,
101)

Too
expensive.
"Engineering
tanks
into
a
`fail­
safe
engineering
condition'
is
prohibitively
expensive
and
unnecessary
as
far
as
Appalachian
production
is
concerned."
(101)

Vacuum
protection.
"Installation
of
vacuum
protection
on
every
tank
could
cost
in
excess
of
$100/
tank.
We
doubt
this
has
been
calculated
in
the
potential
fiscal
impact
of
these
proposals."
(28,
31,
101,
165)

Response:
Good
engineering
practice.
We
agree
with
the
commenter
that
we
should
retain
this
section
as
a
requirement
both
to
improve
spill
prevention
and
to
avoid
confusion
among
the
regulated
community
because
of
the
similar
requirement
for
bulk
storage
containers
at
facilities
other
than
production
facilities.
Therefore,
there
are
no
new
costs.
Nevertheless,
we
believe
that
the
costs
of
these
measures
are
not
excessive
for
small
or
large
facilities
because
you
have
flexibility
as
to
which
measures
you
use,
and
may
choose
the
least
expensive
alternative
listed
in
§112.9(
c)(
4).
For
example,
should
vacuum
protection
be
too
costly,
you
are
free
to
use
another
alternative.
Furthermore,
you
may
also
deviate
from
the
requirement
under
§112.7(
a)(
2)
if
you
can
explain
nonconformance
and
provide
equivalent
environmental
protection
by
some
other
means.
We
revised
the
paragraph
on
vacuum
protection
to
clarify
that
the
rule
addresses
any
type
of
transfer
from
the
tank,
not
merely
a
pipeline
run.

Vacuum
protection.
We
note
that
the
rule
does
not
require
vacuum
protection,
merely
consideration
of
its
use.
You
may
choose
to
use
vacuum
protection,
another
of
the
listed
measures,
or
an
alternative
that
provides
equivalent
environmental
protection.

XII
­
E:
Facility
transfer
operations
­
§112.9(
d)
(proposed
as
§112.9(
e))

Background:
Current
§112.7(
e)(
5)(
iv)
provides
requirements
for
facility
transfer
operations
for
onshore
oil
production
facilities.
In
§112.
7(
e)(
5)(
iv)(
A),
an
owner
or
operator
is
required
to
examine
"periodically
on
a
scheduled
basis"
all
aboveground
valves
and
pipelines.
In
§112.7(
e)(
5)(
iv)(
B),
an
owner
or
operator
is
required
to
examine
salt
water
disposal
facilities
"often."
In
§112.
7(
e)(
5)(
iv)(
C),
an
owner
or
operator
is
required
to
have
a
program
of
flowlines
maintenance
for
their
production
facilities
and
we
list
specific
elements
that
the
program
must
include,
such
as
periodic
examinations
and
adequate
records,
as
appropriate
for
the
individual
facility.

In
1991,
we
redesignated
§112.7(
e)(
5)(
iv)(
A)­(
C)
as
§112.9(
e)(
1)­(
3),
and
proposed
several
changes.
In
§112.9(
e)(
1),
we
proposed
requiring
an
owner
or
operator
to
examine
aboveground
valves
and
piping
monthly,
and
to
include
examination
schedules
285
and
records
in
the
Plan
for
five
years.
We
did
not
propose
any
changes
to
§112.9(
e)(
2).
In
§112.9(
e)(
3),
we
maintained
the
requirement
that
an
owner
or
operator
have
a
flowlines
maintenance
program,
but
proposed
recommending,
rather
than
requiring,
that
he
include
in
the
flowlines
maintenance
program
the
specific
elements
that
the
current
rule
requires.
We
proposed
to
change
this
requirement
to
a
recommendation
because
the
circumstances
of
locations,
staffing,
and
design
vary
between
facilities.
We
also
proposed
changing
the
periodic
examination
requirement
to
a
recommendation
that
an
owner
or
operator
examine
flowlines
monthly.

XII
­
E(
1)
­
Inspection
of
aboveground
valves
and
piping
­
§112.9(
d)(
1)

Comments:
Editorial
suggestion.
The
rule
should
be
clarified
that
"only
inspections
related
to
transfer
operations
are
intended
by
inserting
`associated
with
transfer
operations'
between
`piping'
and
`shall'
in
the
first
line
of
proposed
112.9(
e)(
1)."
(75)

Frequency
of
inspection.

Opposition
to
proposal.

Burdensome.
Such
a
requirement
would
be
unreasonably
burdensome.
The
condition
of
valves
and
piping
does
not
change
significantly
within
a
month.
(67,
91,
133,
173,
187,
L18)

Unwarranted.
"(
I)
nformal,
regular
visual
inspections,
with
no
record
keeping
requirements"
should
continue.
(67)
Field
personnel
routinely
notice
and
fix
any
oil
leaks
associated
with
aboveground
valves
and
pipelines.
(101)
Monthly
inspections
of
aboveground
valves
and
pipelines
"may
not
be
warranted."
(175)

Suggested
alternatives.

Every
6
months.
"The
condition
of
valves
and
piping
does
not
change
significantly
within
a
month's
time.
Therefore,
a
more
appropriate
formal
inspection
frequency
with
documentation
requirements
is
semi­
annual.
More
informal,
regular
visual
inspections,
with
no
record
keeping
requirements
should
continue."
(67,
91,
133,
173,
187,
L18)

Performance
standard
instead.
"The
inspections
standard
...
should
be
amended
to
reflect
a
performance
standard
instead
of
a
prescribed
monthly
inspection....
A
generalized
performance
standard
should
be
included
that
requires
a
minimum
inspection
interval,
such
as
annual
inspection,
which
could
be
altered
to
meet
specific
facility
conditions."
(31,
86,
160)

Recordkeeping.

Opposition
to
proposal.
The
proposed
record
keeping
requirement
is
unnecessary,
of
little
value,
and
"prohibitively
expensive."
(28,
101)
Well
attendants
check
286
Appalachian
Basin
well
sites
(including
all
aboveground
piping,
valves,
joints,
gauges,
pipe
supports,
etc.)
on
a
near­
daily
basis,
noting
necessary
repairs.
Documenting
monthly
examinations
is
unnecessary
and
a
"waste
of
limited
resources
and
time."
It
is
meaningless
to
keep
records
of
inspections
where
no
problems
were
found.
(71)

All
facilities.
We
should
delete
the
record
keeping
requirement
for
all
facilities;
documenting
monthly
visual
inspections
would
drastically
increase
paperwork
with
no
benefit
for
small
facilities.
(70)

PE
certification.
We
should
not
require
PE
approval
of
the
owner's
or
operator's
maintenance
records,
as
these
records
are
included
in
the
Plan.
(101,
165,
L15)

Small
facilities.
We
should
exempt
small
facility
owners
or
operators
from
the
requirement
to
include
aboveground
valve
and
pipeline
examination
schedules
and
records
in
the
Plan
for
five
years.
(58,
86)

Response:
Editorial
suggestion.
We
agree
with
the
commenter
and
have
changed
the
rule
language
to
provide
that
§112.9(
d)(
1)
applies
to
"aboveground
valves
and
piping
associated
with
transfer
operations."

Frequency
of
inspections.
We
have
retained
the
current
inspection
frequency
of
periodic
inspections,
but
editorially
changed
it
to
"upon
a
regular
schedule."
Our
decision
accords
with
the
comment
which
sought
a
performance
standard
instead
of
a
prescribed
monthly
inspection.
The
standard
of
inspections
"upon
a
regular
schedule"
means
in
accordance
with
industry
standards
or
at
a
frequency
sufficient
to
prevent
discharges
as
described
in
§112.1(
b).
Whatever
frequency
of
inspections
is
selected
must
be
documented
in
the
Plan.

Recordkeeping.
We
agree
that
a
five­
year
record
retention
period
is
longer
than
necessary
and
have
deleted
the
proposed
requirement
in
favor
of
the
general
requirement
in
§112.7(
e)
to
maintain
records
for
three
years.
However,
comparison
records
for
compliance
with
certain
industry
standards
may
require
an
owner
or
operator
to
maintain
records
for
longer
than
three
years.

PE
certification.
PE
certification
of
these
inspections
and
records
is
not
required.

Small
facilities.
We
disagree
that
we
should
exempt
either
a
large
or
small
facility
owner
or
operator
from
the
requirement
to
include
aboveground
valve
and
pipeline
examination
schedules
and
records
in
the
Plan
because
those
records
are
needed
to
document
compliance
with
the
rule.

XII
­
E(
2)
Salt
water
disposal
facilities
­
§112.9(
d)(
2)

Comments:
Sudden
change
in
temperature.
"A
sudden
change
of
temperature"
is
a
rather
vague
indicator
of
potential
system
upsets.
This
commenter
assumes
that
the
287
Agency
means
a
rather
sudden
`drop'
(as
in
freezing
temperatures)
that
could
cause
system
upsets.
This
requirement
needs
further
clarification."
(187)

Applicability.
Salt
water
disposal
facility
examination
requirement
should
not
apply
to
storage
facilities
with
de
minimis
amounts
of
oil.
(28,
58,
101)

Frequency
of
inspection.
To
be
consistent
with
other
proposed
inspection
frequencies,
the
inspection
frequency
of
salt
water
disposal
facilities
should
be
quarterly,
rather
than
weekly.
(114)

Response:
Applicability.
The
rule
applies
to
any
regulated
facility
with
salt
water
disposal
if
the
potential
exists
to
discharge
oil
in
amounts
that
may
be
harmful,
as
defined
in
40
CFR
110.3.
This
standard
is
necessary
to
protect
the
environment.

Frequency
of
inspections.
Inspections
of
these
facilities
must
be
conducted
"often."
"Often"
means
in
accordance
with
industry
standards,
or
more
frequently,
if
as
noted,
conditions
warrant.
Whatever
frequency
of
inspections
chosen
must
be
documented
in
the
Plan.

Sudden
change
in
temperature.
A
sudden
change
in
temperature
means
any
abrupt
change
in
temperature,
either
up
or
down,
which
could
cause
system
upsets.

XII­
E(
3)
Flowlines
maintenance
­
§112.9(
d)(
3)

Background:
In
1991,
in
§112.7(
e)(
3)
(redesignated
in
the
final
rules
as
§112.9(
d)(
3)),
we
maintained
the
requirement
that
an
owner
or
operator
have
a
flowlines
maintenance
program,
but
proposed
recommending,
rather
than
requiring
the
owner
or
operator
to
include
in
the
flowlines
maintenance
program
the
specific
elements
that
the
current
rule
requires.
We
also
changed
the
periodic
examination
requirement
to
a
recommendation
that
owners
or
operators
examine
flowlines
monthly.

Comments:
Applicability.

Small
facilities.
Asks
that
we
exempt
small
facilities
from
the
flowlines
maintenance
program
requirement.
(58)

Frequency
of
inspections.

Opposition
to
proposal.
We
should
delete
the
entire
recommendation,
and
keep
only
the
requirement
that
production
facility
owners
or
operators
have
a
flowlines
maintenance
program.
(121)

Costly.
It
is
cost­
prohibitive
and
impossible
for
owners
or
operators
of
Appalachian
oil
gathering
line
systems
to
provide
corrosion
protection
for
the
bare
steel
pipe
used
in
these
systems.
The
"use
of
coated
lines
and
cathodic
protection
is
cost
prohibitive."
(28,
31,
101,
165,
L15)
288
Impossible.
"These
oil
gathering
line
systems
are
buried
in
colder
parts
of
the
Appalachian
basin,
and
monthly
inspection
of
them
is
thus
not
possible."
(28,
31,
165,
L15)

Lack
of
manpower.
Owners
or
operators
do
not
have
enough
manpower
to
inspect
flowlines
monthly.
(91,
133,
173)

Unwarranted.
"Unless
a
flowline
is
known
to
have
problems,
monthly
inspections
may
not
be
warranted.
Many
production
facilities
are
unmanned
and
the
cumulative
length
of
flowlines
can
be
several
miles,
so
the
proposed
monthly
timeframe
may
be
burdensome."
(175)

Suggested
inspection
alternatives.

Periodic.
"Periodic
inspections
based
on
engineering
judgment
and
historical
data
are
sufficient
to
detect
any
significant
deterioration
in
flowline
condition."
(67,
85,
91,
160,
173,
175)

Quarterly.
(114)

Semi­
annual.
(L18)

Annual.
(133).

Response:
Applicability.
A
program
of
flowlines
maintenance
is
necessary
to
prevent
discharges
both
at
large
and
small
facilities.
However,
we
have
deleted
the
proposed
recommendation
regarding
the
specifics
of
the
program
from
the
rule.
We
took
this
action
because
we
are
not
including
recommendations
in
the
rule
in
order
not
to
confuse
the
public
over
what
is
mandatory
and
what
is
discretionary.
This
rule
contains
only
mandatory
requirements.

Corrosion
protection,
flowlines
replacement.
While
we
have
deleted
the
recommendation
from
rule
text
due
to
reasons
explained
above
and
therefore,
the
rule
imposes
no
new
costs,
we
recommend
corrosion
protection,
we
recommend
corrosion
protection,
and
flowlines
replacement
when
necessary,
because
those
measures
help
to
prevent
discharges
as
described
in
§112.1(
b).

Cost.
We
disagree
that
the
cost
of
this
requirement
is
excessive
or
impossible.
We
do
not
prescribe
the
specifics
of
the
program
and
the
owner
or
operator
may
use
any
program
(not
necessarily
the
most
expensive)
effective
to
maintain
the
flowlines
and
prevent
a
discharge
as
described
in
§112.1(
b).
The
requirement
is
a
current
one
and
is
necessary
to
prevent
discharges
as
described
in
§112.1(
b).

Frequency
of
inspections.
In
the
proposed
recommendation
we
suggested
that
you
conduct
monthly
inspections
for
a
flowlines
maintenance
program.
We
now
recommend
that
you
conduct
inspections
either
according
to
industry
standards
or
at
a
frequency
289
sufficient
to
prevent
a
discharge
as
described
in
§112.1(
b).
Under
§112.3(
d)(
1)(
iii),
the
Professional
Engineer
must
certify
that
the
Plan
has
been
prepared
in
accordance
with
good
engineering
practice,
including
consideration
of
applicable
industry
standards.
290
Category
XIII:
Plan
requirements
for
onshore
drilling/
workover
facilities
­
§112.10
Background:
Under
§112.7(
e)(
6)(
i)
of
the
current
rule,
an
onshore
drilling
and
workover
facility
owner
or
operator
must
position
or
locate
mobile
drilling
or
workover
equipment
to
prevent
spilled
oil
from
reaching
navigable
waters.
Section
112.7(
e)(
6)(
ii)
requires
that,
depending
on
location,
it
may
be
necessary
to
use
catchment
basins
or
diversion
structures
to
intercept
and
contain
spills
of
fuel,
crude
oil,
or
oily
drilling
fluids.
Section
112.
7(
e)(
6)(
iii)
requires
the
owner
or
operator
install
a
blowout
prevention
(BOP)
assembly
and
well
control
system
before
drilling
below
any
casing
string
or
during
workover
operations.

In
1991,
we
redesignated
§112.7(
e)(
6)(
i),
(ii),
and
(iii)
as
§112.
10(
b),
(c),
and
(d),
respectively.
We
proposed
to
add
§112.10(
a),
which
proposed
that
in
addition
to
the
specific
spill
prevention
and
containment
procedures
listed
under
§112.10,
an
onshore
oil
drilling
and
workover
facility
owner
or
operator
must
also
address
the
general
requirements
listed
in
§112.7.
Under
proposed
§112.10(
b),
an
owner
or
operator
would
have
to
locate
mobile
drilling
or
workover
equipment
to
prevent
spilled
oil
discharges.
Under
proposed
§112.10(
c),
we
proposed
that
depending
on
the
location,
catchment
basins
or
diversion
structures
may
be
necessary
to
intercept
and
contain
spills
of
fuel,
crude
oil,
or
oily
drilling
fluids.
Under
proposed
§112.10(
d),
we
proposed
to
require
that
when
necessary,
before
drilling
below
any
casing
string
or
during
workover
operations,
an
owner
or
operator
install
a
blowout
prevention
assembly
and
well
control
system
capable
of
controlling
any
wellhead
pressure
that
may
be
encountered
while
that
blowout
assembly
is
on
the
well.

Comments:
Support
for
proposal.
Section
§112.10
requirements
should
include
workover
and
drilling
equipment,
human
activity
is
often
associated
with
accidental
releases.
(27)

§112.10(
a).
"Change
to:
`In
addition
to
the
specific
spill
prevention
and
containment
procedures
listed
under
this
section,
onshore
oil
drilling
and
workover
facilities
must
also
address
the
requirements
listed
under
section
112.7
and
paragraph
112.8(
c)(
11)
in
the
SPP.
'
(Note:
the
caveat
`excluding
production
facilities'
should
probably
be
removed
from
112.8(
c).)"
(121)
In
§112.10(
a),
we
should
require
an
onshore
oil
drilling
and
workover
facility
owner
or
operator
to
"address
the
applicable
general
requirements."
(128)

Editorial
suggestion.
Asks
for
a
definition
of
"onshore
drilling
and
workover
facilities."
(154)

§112.10(
b)
­
We
should
require
positioning
or
locating
mobile
drilling
or
workover
facilities
to
prevent
oil
discharges.
(121)
"We
are
categorically
opposed
to
this
requirement.
The
mobile
drilling
and
workover
contractor
has
absolutely
no
control
as
to
the
location
of
the
rig
unit....
The
contractor
has
no
input
as
to
the
site
design
nor
responsibility
for
its
maintenance."
(128)
Section
112.10(
b)
is
unnecessary
because
it
duplicates
Bureau
of
Land
Management
(BLM)
and
State
regulatory
programs.
(167)
We
should
change
291
§112.10(
b)
to
clarify
that
an
owner
or
operator
must
prevent
spilled
oil
discharges
to
navigable
water.
(L12)

§112.10(
d)
­
The
rule
should
be
revised
to
provide
that:
"Well
service
jobs,
such
as
installing
a
rod
pumping
unit,
may
not
require
a
BOP
assembly
and
associated
well
control
system."
"BOP
are
not
now,
and
should
not
become,
a
requirement
for
all
operations.
Service
jobs
such
as
the
change
out
of
a
rod
pumping
unit,
or
the
batch
treatment
of
a
well
with
corrosion
inhibitor
are
minimal
risk
operations
and
do
not
normally
require
the
use
of
BOP
systems.
These
service
jobs
are
minimal
risk
because
they
can
be
performed
with
existing
wellhead
equipment
in
place.
If
any
unexpected
pressure
is
incurred
during
the
service
job,
then
existing
valves
can
be
utilized
to
control
the
pressure."
(67,
91)

Gauge
negative.
We
should
explain
the
term
gauge
negative.
(110)

Response:
Support
for
proposal.
We
appreciate
the
commenter
support.

§112.10
­
We
disagree
that
an
onshore
oil
drilling
and
workover
facility
owner
or
operator
must
address
the
§112.8(
c)(
11)
requirements
for
mobile
or
portable
oil
storage
tanks
unless
he
has
such
containers.
Section
112.8(
c)(
11)
pertains
only
to
onshore
bulk
storage
containers
(except
production
facilities).

§112.10(
a)
­
We
also
disagree
that
it
is
necessary
to
revise
the
rule
to
require
compliance
with
applicable
§112.7
general
requirements
because
the
owner
or
operator
must
address
all
general
requirements
in
§112.7
and
all
specific
requirements
in
subparts
B
or
C,
as
appropriate,
for
the
type
of
facility
he
owns
or
operates.
If
a
requirement
is
not
applicable,
the
owner
or
operator
must
explain
in
the
Plan
why.

Editorial
suggestion.
The
new
definition
for
"production
facility"
in
§112.
2
includes
the
procedures,
methods,
and
equipment
referenced
in
this
section,
making
a
definition
of
"onshore
drilling
and
workover
facilities"
unnecessary.

§112.10(
b)
­
We
agree
with
the
commenter
that
the
contractor
is
not
normally
responsible
for
site
location,
nor
site
design
or
maintenance.
Such
decisions
are
the
responsibility
of
the
facility
owner
or
operator.
The
owner
or
operator
of
the
facility
has
the
responsibility
to
locate
mobile
equipment
so
as
to
prevent
a
discharge
as
described
in
§112.1(
b).

We
disagree
that
we
should
change
the
word
equipment
to
facilities
in
§112.10(
b).
A
facility
may
include
structures,
piping,
and
equipment.
This
paragraph
is
directed
to
the
threat
of
discharge
from
equipment.

We
have
revised
§112.10(
b)
to
provide
that
an
owner
or
operator
must
position
or
locate
mobile
drilling
or
workover
equipment
to
prevent
a
discharge
as
described
in
§112.1(
b),
rather
than
to
prevent
spilled
oil
discharges,
as
proposed.
A
discharge
as
described
in
292
§112.1(
b)
includes
a
discharge
to
navigable
waters,
adjoining
shorelines,
or
affecting
certain
natural
resources.

We
disagree
that
§112.10(
b)
duplicates
BLM
and
State
regulatory
programs.
The
BLM
program
is
not
specifically
directed
to
preventing
discharges
of
oil,
and
to
the
extent
it
meets
SPCC
requirement,
any
documentation
from
it
may
be
usable
in
an
SPCC
Plan.
Likewise
for
documentation
from
State
regulatory
programs.

§112.10(
d)
­
Where
BOP
assembly
is
not
necessary,
as
for
certain
routine
service
jobs,
such
as
the
installation
of
a
rod
pumping
unit
or
the
batch
treatment
of
a
well
with
corrosion
inhibitor,
the
owner
or
operator
may
deviate
from
the
requirement
under
§112.7(
a)(
2),
and
explain
its
absence
in
the
Plan.
When
BOP
assembly
is
unnecessary
because
pressures
are
not
great
enough
to
cause
a
blowout,
it
is
likewise
unnecessary
to
provide
equivalent
environmental
protection.

Gauge
negative.
Gauge
negative
is
the
pressure
condition
in
a
wellbore
that
results
when
the
pressure
exerted
by
the
hydrocarbon
reservoir
is
less
than
the
hydrostatic
pressure
exerted
by
the
column
of
drilling
fluid
in
the
wellbore.
A
gauge
negative
condition
will
not
give
rise
to
a
pressure
imbalance
likely
to
cause
a
blowout.
See
56
FR
54625.
293
Category
XIV:
Requirements
for
offshore
oil
drilling,
production
,
or
workover
facilities
­
§112.11
Background:
Section
§112.11
includes
SPCC
Plan
requirements
for
an
owner
or
operator
of
an
offshore
oil
drilling,
production,
and
workover
facility.

XIV
­
1
General
and
specific
requirements
­
§112.11(
a)

Comments:
State
rules.
"This
section
should
be
deleted
because
current
State
spill
prevention,
water
discharge,
and
hazardous
material
regulations
adequately
provide
spill
protection
in
inland
water
areas
such
as
lakes,
rivers,
and
wetlands."
(128)

Response:
State
rules.
We
disagree
with
the
commenter
that
these
rules
are
unnecessary
because
not
every
State
has
rules
to
protect
offshore
drilling,
production,
and
workover
facilities.
While
some
States
may
have
rules,
some
State
rules
may
not
be
as
stringent
as
the
Federal
rules.
In
any
case,
Congress
has
intended
us
to
establish
a
nationwide
Federal
program
to
protect
the
environment
from
the
dangers
of
discharges
as
described
in
§112.
1(
b)
posed
by
this
class
of
facilities.
Therefore,
we
have
retained
the
section,
as
modified.
We
note,
however,
that
if
you
have
a
State
SPCC
plan
or
other
regulatory
document
acceptable
to
the
Regional
Administrator
that
meets
all
Federal
SPCC
requirements,
you
may
use
it
as
an
SPCC
Plan
if
you
cross
reference
the
State
or
other
requirements
to
the
Federal
requirement.
If
it
meets
only
some,
but
not
all
Federal
SPCC
requirements,
you
must
supplement
it
so
that
it
meets
all
of
the
SPCC
requirements.

XIV
­
2
Definition
reference;
MMS
jurisdiction
­
proposed
§112.11(
b)

Background:
In
§112.7(
e)(
7)(
i)
of
the
current
rule,
the
term
oil
drilling,
production,
or
workover
facilities
(offshore)
is
defined.
In
1991,
we
redesignated
§112.7(
e)(
7)(
i)
as
§112.11(
b),
and
referenced
the
proposed
§112.2
definition
of
offshore
oil
drilling,
production,
and
workover
facilities.
The
proposed
rule
also
would
have
provided
that
a
facility
subject
to
the
Operating
Orders,
notices,
and
regulations
of
the
Minerals
Management
Service
(MMS)
is
not
subject
to
part
112.

Comments:
We
should
delete
§112.11(
b)
because
it
is
unnecessary.
(121)

Response:
The
proposed
1991
section
referenced
the
definition
of
"offshore
oil
drilling,
production,
and
workover
facility,"
which
is
now
encompassed
within
the
definition
of
"production
facility"
in
§112.
2.
A
new
sentence
would
have
referenced
the
exemption
of
facilities
subject
to
Minerals
Management
Service
(MMS)
Operating
Orders,
notices,
and
regulations
from
the
SPCC
rule.
MMS
jurisdiction
is
outlined
in
Appendix
B
to
part
112.
Since
none
of
the
proposed
language
is
mandatory,
we
have
deleted
it
because
we
have
included
only
mandates
in
this
rule
so
as
not
to
confuse
the
regulated
public
over
what
is
required
and
what
is
discretionary.
We
received
no
substantive
comments
on
this
paragraph.
294
XIV
­
3
Facility
drainage
­
§112.11(
b)
(proposed
as
§112.11(
c))

Background:
In
§112.7(
e)(
7)(
ii)
of
the
current
rule,
requirements
for
oil
drainage
collection
equipment
are
described.
In
1991,
we
redesignated
§112.7(
e)(
7)(
ii)
as
§112.11(
c),
and
proposed
to
require
removal
of
collected
material
from
oil
drainage
"as
often
as
necessary
to
prevent
overflow,
but
not
less
than
once
a
year."

Comments:
Removal
of
collected
oil.
We
should
delete
the
modification
that
owners
or
operators
remove
collected
material
at
"least
once
a
year,"
because
the
current
requirement
is
sufficient.
(31,
86)

Response:
Removal
of
collected
oil.
EPA
agrees
with
the
commenter's
suggestion
that
the
current
rule
is
sufficient
to
prevent
discharges
as
described
in
§112.1(
b),
and
therefore
we
have
deleted
the
"at
least
once
a
year"
standard.
You
must
remove
collected
oil
as
often
as
is
necessary
to
prevent
such
discharges.

XIV
­
4
Sump
systems
­
§112.11(
c)
(proposed
as
§112.11(
d))

Background:
Under
§112.7(
e)(
7)(
iii)
of
the
current
rule,
an
owner
or
operator
of
a
facility
with
a
sump
system
to
adequately
size
the
sump
and
drains
must
have
a
spare
pump
or
equivalent
method
available
for
removing
liquid
from
the
sump,
and
assure
that
oil
does
not
escape.
In
1991,
we
redesignated
§112.7(
e)(
7)(
iii)
as
§112.
11(
d)
(redesignated
in
the
final
rule
as
§112.11(
c)).
We
also
proposed
that
the
owner
or
operator
must
employ
a
monthly
preventive
maintenance
inspection
and
testing
program
to
assure
reliable
operation
of
the
liquid
removal
system
and
pump
start­
up
device.

Comments:
Frequency
of
inspections.
"Semi­
annual,
instead
of
monthly
inspection
and
testing
of
the
liquid
removal
system
would
be
preferable."
(L18)

Response:
Frequency
of
inspections.
We
have
retained
the
current
rule
language
requiring
a
"regularly
scheduled"
preventive
maintenance
program
because
we
believe
that
the
frequency
of
maintenance
should
be
in
accordance
with
industry
standards
or
frequently
enough
to
prevent
a
discharge
as
described
in
§112.1(
b).
Whatever
schedule
is
chosen
must
be
documented
in
the
Plan.

XIV
­
5
Corrosion
protection
­
§112.11(
g)
(proposed
as
§112.11(
h))

Background:
Under
§112.7(
e)(
7)(
vii)
of
the
current
rule,
an
owner
or
operator
must
equip
tanks
with
suitable
corrosion
protection.
In
1991,
we
redesignated
§112.7(
e)(
7)(
vii)
as
§112.11(
h)
(redesignated
in
the
final
rule
as
§112.11(
g)).
We
also
recommended
that
an
owner
or
operator
follow
the
appropriate
National
Association
of
Corrosion
Engineers
standards
for
corrosion
protection.
295
Comments:
Industry
standards.
We
should
either
delete
the
proposed
recommendation
or
make
it
a
requirement
for
new
construction.
(121)
We
should
modify
§112.11(
h)
to
incorporate
other
industry
recommended
corrosion
control
practices,
particularly
STI
standards.
(140)

Response:
Industry
standards.
In
response
to
the
comment,
we
have
deleted
the
recommendation
because
we
do
not
wish
to
confuse
the
regulated
community
over
what
is
mandatory
and
what
is
discretionary.
These
rules
contain
only
mandatory
requirements.
We
expect
that
facilities
will
follow
industry
standards
for
corrosion
protection
as
well
as
other
matters
(see
§112.3(
d)(
iii)),
but
decline
to
prescribe
particular
standards
in
the
rule
text
because
those
standards
are
subject
to
change,
and
we
will
not
incorporate
a
potentially
obsolescent
standard
into
the
rules.

XIV
­
6
Pollution
prevention
system
testing
and
inspection
­
§112.11(
i)
(proposed
as
§112.11(
j))

Background:
Under
§112.7(
e)(
7)(
ix)
of
the
current
rule,
an
owner
or
operator
must
test
and
inspect
pollution
prevention
equipment
and
systems
periodically,
commensurate
with
the
complexity,
conditions,
and
circumstances
of
the
facility.
In
1991,
we
proposed
to
redesignated
§112.7(
e)(
7)(
ix)
as
§112.11(
j)
(redesignated
in
the
final
rule
as
§112.11(
i)).
We
proposed
to
require
that
an
owner
or
operator
use
simulated
spill
testing
to
test
and
inspect
human
and
pollution
control
and
countermeasure
systems,
unless
he
can
demonstrate
that
another
method
provides
equivalent
protection.
We
also
proposed
requiring
periodic
testing
and
inspection
of
pollution
prevention
equipment
at
least
monthly.

Comments:
Frequency
of
testing.
"Simulation
testing
on
a
monthly
basis
is
excessive."
(42,
L12)

Annual
response
drills.
MMS
requires
only
annual
spill
response
drills
for
outer
continental
shelf
operations.
"We
suggest
this
is
an
adequate
frequency.
Requiring
more
frequent
simulations
would
overburden
facility
operators
unnecessarily."
(75,
L12)

Recommendations
instead.
We
should
convert
periodic
reviewing,
testing,
and
inspecting
provisions
from
requirements
to
recommendations.
We
can
not
justify
these
provisions
either
economically
or
as
benefits
conferred
on
society.
(42)

Semi­
annual
testing.
"...(
A)
semi­
annual,
instead
of
monthly,
requirement
for
testing
and
inspection
of
pollution
prevention
equipment
would
be
preferable."
(L18)

Response:
Frequency
of
testing.
We
have
retained
the
current
requirement
for
testing
on
a
"scheduled
periodic
basis"
commensurate
with
conditions
at
the
facility
because
we
believe
that
testing
should
follow
industry
standards
or
be
conducted
at
a
frequency
296
sufficient
enough
to
prevent
a
discharge
as
described
in
§112.1(
b)
rather
than
any
prescribed
time
frame.
Whatever
frequency
is
chosen
must
be
documented
in
the
Plan.

We
disagree
that
we
cannot
justify
the
costs
and
benefits.
This
rule
is
necessary
to
ensure
that
systems
that
prevent
discharges
function
properly.

XIV
­
7
Blowout
prevention
­
§112.11(
k)
(proposed
as
§112.11(
l))

Background:
Under
§112.7(
e)(
7)(
xi)
of
the
current
rule,
before
an
owner
or
operator
drills
below
any
casing
string
and
during
workover
operations,
he
must
install
a
blowout
prevention
(BOP)
assembly
and
well
control
system.
Further,
this
BOP
assembly
and
well
control
system
must
be
capable
of
controlling
any
expected
well­
head
pressure
while
it
is
on
the
well.
In
1991,
we
proposed
to
redesignate
§112.7(
e)(
7)(
xi)
as
§112.11(
l)
(redesignated
in
the
final
rule
as
§112.11(
k)),
but
otherwise
reproposed
without
substantive
change.

Comments:
Alternatives.
"There
are
occasions
where
this
is
not
warranted
or
impractical
to
implement."
Exception
should
be
made
for
drilling
below
conductor
casing.
(L12)

Response:
Alternatives.
The
question
of
whether
blowout
prevention
is
warranted
or
impractical
or
not
for
drilling
below
conductor
casing
is
one
of
good
engineering
practice.
Acceptable
alternatives
may
be
permissible
under
the
rule
permitting
deviations
(§
112.7(
a)(
2))
when
the
owner
or
operator
states
the
reasons
for
nonconformance
and
provides
equivalent
environmental
protection
in
another
way.

XIV
­
8
Extraordinary
well
control
measures
­
§112.11(
m)

Background:
Under
§112.7(
e)(
7)(
xii)
of
the
current
rule,
an
owner
or
operator
must
provide
extraordinary
well
control
measures
in
the
event
of
an
emergency.
In
1991,
we
proposed
to
redesignate
§112.7(
e)(
7)(
xii)
as
§112.11(
m).
We
proposed
to
recommend
–
instead
of
to
require
–
that
an
owner
or
operator
provide
extraordinary
well
control
measures
if
emergency
conditions
occur
(e.
g.,
fire,
loss
of
control).
We
also
recommended
varying
the
degree
of
control
system
redundancy
with
hazard
exposure
and
probable
failure
consequences.
Further,
we
recommended
that
an
owner
or
operator
include
redundant
or
"fail
close"
valving
in
surface
shut­
in
systems.

Comments:
We
should
delete
proposed
§112.11(
m)
or
make
it
a
requirement.
(121)

Response:
In
response
to
comment,
we
have
deleted
the
text
of
the
recommendations
from
the
rules
because
we
do
not
wish
to
confuse
the
regulated
community
over
what
is
mandatory
and
what
is
discretionary.
However,
we
endorse
its
substance.
This
rule
contains
only
mandatory
requirements.

XIV
­
9
Piping;
corrosion
protection
­
§112.11(
n)
(proposed
as
§112.11(
p))
297
Background:
In
§112.7(
e)(
7)(
xvi)
of
the
current
rule,
we
require
an
owner
or
operator
to
protect
from
corrosion
all
piping
appurtenant
to
the
facility.
In
1991,
we
proposed
to
redesignate
§112.7(
e)(
7)(
xvi)
as
§112.11(
p)
(redesignated
in
the
final
rule
as
§112.11(
n)),
and
proposed
to
retain
the
requirement.
We
also
proposed
to
recommend
–
rather
than
to
require
–
that
the
owner
or
operator
discuss
in
the
SPCC
Plan
the
corrosion
protection
method
used,
such
as
protective
coatings
or
cathodic
protection.

Comments:
We
should
delete
the
recommendation
that
an
owner
or
operator
discuss
the
corrosion
protection
method
used
in
the
SPCC
Plan.
(121)

Response:
In
response
to
comment,
we
have
deleted
the
recommendation
to
discuss
the
method
of
corrosion
protection,
because
it
is
surplus.
In
your
SPCC
Plan,
you
must
discuss
the
method
of
corrosion
protection
you
use.
See
112.7(
a)(
1).

XIV
­
10
Written
instructions
for
contractors
­
proposed
§112.11(
s)

Background:
Under
§112.7(
e)(
7)(
xiii)
of
the
current
rule,
an
owner
or
operator
must
prepare
written
instructions
for
contractors
and
subcontractors
to
follow
whenever
contract
activities
involve
servicing
a
well
or
systems
appurtenant
to
a
well
or
pressure
vessel.
In
1991,
we
proposed
to
redesignate
§112.7(
e)(
7)(
xiii)
as
§112.
11(
s).
We
proposed
to
recommend
–
rather
than
require
–
that
the
owner
or
operator
prepare
written
instructions
for
contractors
or
subcontractors
to
follow
in
such
circumstances.

Comments:
Liability.
"The
regulations
appear
to
mandate
involvement
and
control
by
an
operator
over
the
activities
of
contractors
who
perform
services
on
offshore
facilities.
This
creates
two
very
serious
problems.
First,
the
contractors
are
hired
to
perform
special
services.
The
contractor
is
able
to
do
his
work
more
safely
if
he
is
allowed
to
direct
his
own
activities.
Second,
operators
expose
themselves
to
various
types
of
liability
by
virtue
of
the
degree
of
control
exercised
over
contractors."
(42)

Requirement
instead.
We
should
continue
to
require
–
rather
than
recommend
–
that
owners
or
operators
prepare
written
instructions
for
on­
site
contractors
and
subcontractors.
(121)

Response:
We
have
deleted
the
proposed
recommendation
because
we
wish
to
avoid
confusing
the
regulated
community
over
what
is
mandatory
and
what
is
discretionary.
This
rule
contains
only
mandatory
requirements.
298
Category
XV:
Relationship
to
other
programs
of
the
rule
XV­
A:
UST­
part
112
Background:
In
1991,
we
noted
that
a
number
of
underground
and
aboveground
oil
storage
tanks
are
subject
to
both
the
SPCC
regulation
(40
CFR
part
112)
and
the
underground
storage
tank
(UST)
regulation
(40
CFR
part
280).
In
§112.1(
d)(
2)(
i)
and
(ii),
we
proposed
that
the
calculation
of
a
facility's
underground
and
aboveground
storage
capacity
should
not
include
USTs,
as
defined
in
§112.2(
v).
To
avoid
duplicative
regulation,
in
§112.1(
d)(
4),
we
proposed
to
exclude
from
SPCC
regulation
USTs
subject
to
the
technical
requirements
of
40
CFR
part
280,
reasoning
that
the
UST
program
offered
comparable
environmental
protection.
We
noted
that
USTs
not
subject
to
all
of
the
technical
requirements
of
the
UST
provisions
would
be
subject
to
the
SPCC
requirements.
We
also
noted
that
the
SPCC
program
would
still
regulate
tanks
that
are
not
completely
buried,
because
tanks
with
exposed
surfaces
exhibit
a
greater
potential
to
discharge
oil
into
navigable
waters
and
other
surface
waters.

Comments:
For
comments
on
this
issue,
see
section
IV.
B
of
this
document.

Response:
See
section
IV.
B
of
this
document
for
response.

XV
­
B:
State
programs,
SARA
Title
III,
wellhead
protection,
flood­
related
requirements,
OSHA,
and
industry
standards
­
part
112
Background:
In
the
preamble
to
the
1991
proposed
rule,
we
discussed
the
relationship
between
the
SPCC
regulation
and
other
programs,
including
State
programs;
the
Superfund
Amendments
and
Reauthorization
Act
(SARA)
Title
III
or
the
Emergency
Planning
and
Community
Right­
to­
Know
Act
(EPCRA);
State
wellhead
protection
(WHP)
programs
under
the
Safe
Drinking
Water
Act
(SDWA);
flood­
related
requirements
under
Executive
Order
(EO)
11988,
"Floodplain
Management;"
and
the
Occupational
Safety
and
Health
Act
(OSHA).

XV­
B­
1
State
programs
Background:
See
section
X.
K
of
this
document.

Comments:
For
comments
on
State
issues,
see
section
X.
K
of
this
document.

Response:
For
responses
on
State
issues,
see
section
X.
K
of
this
document.

XV­
B­
2
SARA
Title
III
and
wellhead
protection
Background:
In
1991,
we
specified
how
coordination
between
Federal,
State,
and
local
agencies
is
possible
through
additional
authorities
–
SARA
Title
III
in
particular.
We
said
that
we
expected
to
work
closely
with
States
to
develop
mechanisms
for
sharing
299
information
about
facilities
and
oil
discharges
to
improve
environmental
protection
and
public
health.
We
indicated
that
the
proposal
requires
an
owner
or
operator
to
ensure
that
any
SPCC
contingency
plan
is
compatible
and
coordinated
with
local
emergency
plans,
including
those
developed
under
SARA
Title
III.

We
noted
that
States
must
adopt
and
submit
to
EPA
a
wellhead
protection
(WHP)
program.
We
also
noted
that
an
owner
or
operator
must
comply
with
both
the
State
WHP
program
and
the
SPCC
regulations,
and
that
meeting
the
SPCC
requirements
did
not
necessarily
ensure
compliance
with
a
State
WHP
program.

Comments:
Support
for
coordination.
Support
for
coordination
of
the
SPCC
program
with
SARA
Title
III.
(29,
11)
Support
for
coordination
with
WHP
programs.
(27)

Response:
Support
for
coordination.
We
appreciate
commenter
support.

XV­
B­
3
Flood­
related
requirements
Background:
In
§§
112.8(
b)(
6)
and
112.9(
c)(
3),
we
recommended
–
in
accordance
with
EO
11988,
"Floodplain
Management"
–
that
the
SPCC
Plan
address
precautionary
measures
for
facilities
in
locations
subject
to
flooding.
We
noted
that
the
National
Flood
Insurance
Program
(NFIP)
definition
of
structures
included
ASTs.
We
described
some
of
NFIP's
requirements
and
standards,
and
encouraged
owners
or
operators
to
consider
and
comply
with
the
requirements
in
44
CFR
60.3
when
preparing
and
implementing
an
SPCC
Plan.
We
also
proposed
recommending
that
an
SPCC
Plan
"address
precautionary
measures
for
facilities
in
locations
subject
to
flooding."
In
proposed
§§
112.8(
b)(
6)
and
112.9(
c)(
3),
we
recommended
that
the
SPCC
Plan
"address
additional
requirements
for
events
that
occur
during
a
period
of
flooding."

Comments:
Editorial
suggestion.
We
should
move
issues
related
to
flooding
from
the
prevention­
related
SPCC
requirements
to
the
SPCC
contingency
plan
requirements
in
§112.7(
c).
(12)

Mitigation
measures
of
NFIP.
"At
a
minimum,
EPA
should
address
the
mitigation
measures
of
the
National
Flood
Insurance
Program
(NFIP)
...
more
definitively
in
the
rule
rather
than
addressing
them
under
the
preamble."
"At
a
minimum,
...,
facility
owners
or
operators
should
undertake
the
following:
1)
Identify
whether
the
facility
is
located
in
a
floodplain
in
the
SPCC
plan;
2)
if
the
facility
is
located
in
the
floodplain,
the
SPCC
plan
should
address
to
what
extent
it
meets
the
minimum
requirements
of
the
NFIP;
and
3)
if
a
facility
does
not
meet
the
minimum
requirements
of
the
NFIP,
the
SPCC
plan
should
address
appropriate
precautionary
and
mitigation
measures
for
potential
flood­
related
discharges."
EPA
should
also
consider
requiring
facilities
in
areas
subject
to
500­
year
events
to
address
minimum
NFIP
standards.
(12)

NPDES
rules.
The
proposed
requirements
are
duplicative
of,
and
may
conflict
with,
storm
water
regulations.
(35)
300
Recommendation
or
requirement.
We
should
require
–
rather
than
recommend
–
that
NFIP
facility
owners
or
operators
address
precautionary
and
mitigation
measures
in
the
SPCC
Plan.
(3,
12,
27,
114,
121)
Since
oil
storage
facilities
could
cause
significant
environmental
damage
and
impact
health
and
safety
in
a
flood,
we
should
require
that
in
areas
subject
to
a
500­
year
flood
event,
a
facility
owner
or
operator
must
address
NFIP
standards
in
the
SPCC
Plan.
We
should
clarify
that
§§
112.8(
b)(
6)
and
112.9(
c)(
3)
reflect
the
preamble
language.
(12)

Subject
to
flooding.
We
should
clarify
the
term
subject
to
flooding.
(9,
27,
115)

Response:
Recommendation
or
requirement.

§112.8(
b)(
6).
We
deleted
this
recommendation
because
it
is
more
appropriately
addressed
in
FEMA
rules
and
guidance,
including
the
definitions
the
commenters
referenced.
We
disagree
that
the
proposed
recommendation
should
be
made
a
requirement
because
flood
control
plans
and
design
capabilities
for
discharge
systems
are
provided
for
under
the
storm
water
regulations,
and
further
Federal
regulations
would
be
duplicative.

Other
Federal
rules
also
apply,
making
further
SPCC
rules
unnecessary.
Oil
storage
facilities
are
considered
structures
under
the
National
Flood
Insurance
Program
(NFIP),
and
therefore
such
structures
are
subject
to
the
Regulations
for
Floodplain
Management
at
44
CFR
60.3.
Some
of
the
specific
NFIP
standards
that
may
apply
for
aboveground
storage
tanks
include
the
following:
(1)
tanks
must
be
designed
so
that
they
are
elevated
to
or
above
the
base
flood
level
(100­
year
flood)
or
be
designed
so
that
the
portion
of
the
tank
below
the
base
flood
level
is
watertight
with
walls
substantially
impermeable
to
the
passage
of
water,
with
structural
components
having
the
capability
of
resisting
hydrostatic
and
hydrodynamic
loads,
and
with
the
capability
to
resist
effects
of
buoyancy
(44
CFR
60.3(
a)(
3));
(2)
tanks
must
be
adequately
anchored
to
prevent
flotation,
collapse
or
lateral
movement
of
the
structure
resulting
from
hydrodynamic
and
hydrostatic
loads
and
the
effects
of
buoyancy
(40
CFR
60.3(
c)(
3));
for
structures
that
are
intended
to
be
made
watertight
below
the
base
flood
level,
a
Registered
Professional
Engineer
must
develop
and/
or
review
the
structural
design,
specifications,
and
plans
for
construction,
and
certify
that
they
have
been
prepared
in
accordance
with
accepted
standards
and
practice
(40
CFR
60.3(
c)(
4));
and,
tanks
must
not
encroach
within
the
adopted
regulatory
floodway
unless
it
has
been
demonstrated
that
the
proposed
encroachment
would
not
result
in
any
increase
in
flood
levels
within
the
community
during
the
occurrence
of
the
base
flood
discharge
(40
CFR
60.3(
d)).
Additionally,
the
NFIP
has
specific
standards
for
coastal
high
hazard
areas.
See
40
CFR
60.3(
e)(
4).

§112.9(
c)(
1).
We
have
deleted
the
recommendation
because
we
do
not
wish
to
confuse
the
regulated
public
over
what
is
mandatory
and
what
is
discretionary.
These
rules
contain
only
mandatory
requirements.
However,
we
support
the
substance
of
the
recommendation,
and
suggest
that
a
facility
in
an
area
prone
to
301
flooding
either
follow
the
requirements
of
the
NFIP
or
employ
other
methods
based
on
good
engineering
practice
to
minimize
damage
to
the
facility
from
a
flood.

Subject
to
flooding.
Because
we
have
not
adopted
the
recommendation
that
an
owner
or
operator
address
precautionary
measures
for
facilities
located
in
areas
subject
to
flooding,
we
have
not
defined
the
term
subject
to
flooding,
nor
have
we
moved
it
to
§112.7(
c).

XV­
B­
4
OSHA
Background:
In
1991,
we
said
that
a
number
of
AST
owners
or
operators
are
subject
to
OSHA
requirements
under
29
CFR
1910.106,
and
we
described
some
of
these
OSHA
requirements.
We
noted
that
these
requirements
are
important
for
implementing
effective
spill
prevention
programs
and
should
be
incorporated
into
SPCC
Plans
using
good
engineering
practice.

Comments:
Asks
why
we
said
that
OSHA
requirements
are
necessary
for
an
effective
spill
prevention
program,
when
OSHA
requirements
"stand
on
their
own."
Inclusion
of
OSHA
requirements
in
the
SPCC
Plan
would
be
unnecessarily
duplicative.
(34)
"We
do
not
recall
an
OSHA
requirement
that
dike
walls
must
average
six
feet
in
height
and
that
earthen
dikes
must
be
three
feet
in
height
and
two
feet
wide
at
the
top.
Where
in
the
regulations
are
these
requirements
located.
(101,165,
L15)

Response:
We
agree
that
OSHA
requirements
are
independent
of
SPCC
requirements.
It
is
not
necessary
to
duplicate
compliance
with
those
requirements
in
an
SPCC
Plan.

XV­
B­
5
Industry
standards
Comments:
We
should
include
applicable
industry
standards
in
the
SPCC
regulation.
(46)
Our
proposal
is
superfluous
for
smaller
capacity
ASTs
because
ASTs
and
petroleum
hazardous
substances
are
"de
facto
regulated"
by
fire
and
safety
authorities
(e.
g.,
the
National
Fire
Protection
Association,
the
Western
Fire
Chiefs
Association,
and
the
National
Building
Code
Association).
(50)
Urges
referencing
of
Steel
Tank
Institute
standards
in
rule.
(140)

Response:
Throughout
the
rule
we
generally
allow
for
the
application
of
industry
standards
where
the
standards
are
both
specific
and
objective,
and
their
application
may
reduce
the
risk
of
discharges
to
and
impacts
to
the
environment.
We
recognize
that
as
technology
advances,
specific
standards
change.
By
referencing
industry
standards
throughout
the
preamble,
we
anticipate
that
the
underlying
requirements
of
the
rule
itself
will
change
as
new
technology
comes
into
use
without
the
need
for
further
amendments.
We
believe
that
industry
standards
today
represent
good
engineering
practice
and
generally
are
environmentally
protective.
However,
if
an
industry
standard
changes
in
a
way
that
would
increase
the
risk
of
a
discharge
as
described
in
§112.1(
b),
EPA
will
apply
and
enforce
the
present­
day
standard
(or,
if
that
is
not
possible,
its
equivalent
in
riskassessment
terms)
rather
than
the
future,
less
protective
standard.
302
Under
the
terms
of
this
rule,
when
there
is
no
specific
and
objective
industry
standard
that
applies
to
your
facility
(for
example,
whether
there
is
no
standard
or
a
standard
that
uses
the
terms
"as
appropriate,"
"often,"
"periodically,"
and
so
forth),
you
should
instead
follow
any
specific
and
objective
manufacturer's
instructions
for
the
use
and
maintenance
or
installation
of
the
equipment,
appurtenance,
or
container.
If
there
is
neither
a
specific
and
objective
industry
standard
nor
a
specific
and
objective
manufacturer's
instruction
that
applies,
then
it
is
the
duty
of
the
PE
under
§112.3(
d)
to
establish
such
specific
and
objective
standards
for
the
facility
and,
under
§112.3(
d),
he
must
document
these
standards
in
the
Plan.
If
the
PE
specifies
the
use
of
a
specific
standard
for
implementation
of
the
Plan,
the
owner
or
operator
must
also
reference
that
standard
in
the
Plan.

Throughout
today's
preamble,
we
list
industry
standards
that
may
assist
an
owner
or
operator
to
comply
with
particular
rules.
The
list
of
those
standards
is
merely
for
your
information.
They
may
or
may
not
apply
to
your
facility,
but
we
believe
that
their
inclusion
is
helpful
because
they
generally
are
applicable
to
the
topic
referenced.
The
decision
in
every
case
as
to
the
applicability
of
any
industry
standard
will
be
one
for
the
PE.

For
your
convenience,
we
are
including
a
list
of
organizations
in
today's
preamble
that
may
be
helpful
in
the
identification
and
explanation
of
industry
standards.
1
See
Analysis
of
the
Number
of
Facilities
Regulated
by
EPA's
SPCC
Program
and
Analysis
of
the
Applicability
of
EPA's
SPCC
Program
to
the
Electric
Utility
Industry,
June
1996,
U.
S.
EPA.

303
Category
XVI:
Economic
analysis
Background:
In
1991,
we
prepared
two
preliminary
economic
analyses:
"Economic
Impact
Analysis
of
the
Proposed
Revisions
to
the
Oil
Pollution
Prevention
Regulation,"
and
"Supplemental
Cost
and
Benefit
Analysis
of
the
Proposed
Revisions
to
the
Oil
Pollution
Prevention
Regulation."
The
first
analysis
developed
cost
estimates
for
the
proposed
notification
along
with
three
other
proposed
requirements
that
were
determined
to
result
in
non­
negligible
costs
to
the
regulated
community.
The
second
analysis
estimated
the
economic
effects
of
the
proposed
rule
based
on
alternative
expectations
about
how
the
regulated
community
would
interpret
certain
proposed
revisions.
We
presented
the
results
of
these
studies
in
the
preamble
to
the
proposed
rulemaking
and
invited
comment
on
both
the
methodology
used
and
the
results
obtained.

XVI
­
A:
Estimated
universe
of
regulated
facilities
Comments:
Electrical
equipment.
The
Economic
Impact
Analysis
underestimated
the
number
of
electric
utility
facilities
subject
to
the
SPCC
regulations.
As
many
as
100,000
electric
utility
facilities
­­
including
48,
000
electrical
substation­
type
facilities,
48,
000
industrial
or
commercial
customer
locations,
and
1,600
other
locations
­­
could
be
subject
to
the
rule.
This
figure
could
include
80,
000
electric
utility
sites.
As
a
result,
these
figures
would
result
in
industry­
wide
costs
of
$2
billion
and
$1
billion,
respectively.
(125,
175)

Production
facilities.
We
should
revise
the
number
of
oil
production
facilities
included
in
the
economic
analyses
to
reflect
the
final
division
of
responsibility
between
the
Department
of
the
Interior
(DOI)
and
EPA
as
required
by
Executive
Order
(EO)
12777.
We
did
not
include
in
the
analyses
a
facility
category
encompassing
drilling
rigs
and
workover
units.
Since
we
included
such
a
category
of
operations
in
the
regulations,
we
should
include
these
operations
in
the
economic
analyses
as
well.
(128)

Truck
st
ops.
Our
Economic
Impact
Analysis
(EIA)
and
Supplemental
Cost
and
Benefit
Analysis
do
not
identify
truck
stops
as
a
facility
category,
and
was
therefore
concerned
that
the
US
truck
stop
industry
would
not
be
subject
to
the
SPCC
regulations.
(43)

Response:
Electrical
equipment.
The1995
SPCC
Survey
indicated
that
about
2,600
electric
utility
industry
facilities
were
regulated
by
the
program.
We
later
increased
our
estimate
to
3,700
to
account
for
possible
shortcomings
in
the
development
of
the
original
estimate.
1
We
recognized
the
possibility
that
the
large
number
of
transformers
and
other
types
of
oil­
filled
electrical
equipment
that
are
associated
with
the
estimated
3,700
primary
electric
utility
establishments
may
not
have
been
fully
reflected
in
the
burden
estimates
for
electric
utilities
included
in
the
1991
proposed
rulemaking
analyses.
As
a
result,
we
have
reflected
in
the
Information
Collection
Request
(ICR)
and
economic
analysis
for
the
final
rule
an
increase
in
the
unit
burden
for
a
primary
electric
utility
establishment
to
account
for
associated
oil­
filled
electrical
equipment
(e.
g.,
transformers).
304
As
a
result
of
these
changes
made
to
the
final
rule,
we
expect
many
utilities
to
see
a
decline
in
compliance
costs.

Production
facilities.
We
conducted
a
survey
of
oil
storage
and
production
facilities
in
1995
to
better
estimate
the
number
of
regulated
facilities.
This
survey
defined
oil
production
facilities
as
leases,
which
corresponds
to
the
definition
found
in
the
SPCC
rule.
In
the
oil
industry,
a
lease
is
generally
regarded
as
a
single
oil
field
operated
by
a
single
operator.
At
the
time
of
the
survey,
we
had
already
signed
a
Memorandum
of
Understanding
(MOU)
with
DOI
and
the
Department
of
Transportation
(DOT)
(February
3,
1994)
that
redelegated
the
responsibility
to
regulate
certain
offshore
facilities
located
in
and
along
the
Great
Lakes,
rivers,
coastal
wetlands,
and
the
Gulf
Coast
barrier
islands
from
DOI
to
EPA.
As
a
result,
the
1995
survey
provided
us
with
a
revised
estimate
of
the
total
number
of
oil
production
facilities
regulated
under
the
SPCC
program,
including
drilling
rigs
and
workover
units.
We
used
this
estimate
to
calculate
the
economic
effects
associated
with
the
final
rule.

Truck
st
ops.
In
the
1995
survey,
we
classified
truck
stops
as
gasoline
service
stations
to
the
extent
that
they
both
share
the
same
primary
Standard
Industrial
Classification
(SIC)
Code
(5541).
Regardless
of
their
SIC
Code,
facilities
are
subject
to
the
requirements
of
the
SPCC
regulation
based
on
the
total
amount
of
oil
storage
capacity
and
the
reasonable
possibility
of
a
discharge
as
described
in
§112.
1(
b).
As
a
result,
all
truck
stops
that
have
an
oil
storage
capacity
greater
than
1,320
gallons
aboveground
or
42,000
gallons
underground
are
subject
to
the
SPCC
requirements.
However,
completely
buried
storage
capacity
subject
to
all
of
the
technical
requirements
of
40
CFR
part
280
or
a
State
program
approved
under
40
CFR
part
281
does
not
count
in
the
calculation
of
part
112
storage
capacity.

XVI
­
B:
Impacts
on
small
businesses
Comments:
Costs.
We
underestimated
the
cost
and
level
of
effort
necessary
to
develop
Plans
that
would
meet
the
requirements
we
proposed
in
1991.
(16,
36,
110)
The
proposed
regulation
"would
significantly
impact
small
operators."
(28)
The
regulation
imposes
costs,
but
does
not
provide
any
incremental
benefit.
(28,
31,
34)
Our
proposed
administrative
and
training
requirements
would
overpower
small
facilities.
(72,
178)
The
regulations
would
drastically
impact
small
oil
production
facilities,
although
these
facilities
rarely
have
the
types
of
spills
the
SPCC
rule
is
intended
to
correct.
If
adopted,
the
proposed
rule
would
compel
extremely
costly
facility
changes,
and
would
be
economically
detrimental
to
Appalachian
Producers.
(101)
The
proposed
rule
could
contribute
to
the
elimination
of
many
members
of
the
New
York
oil
and
gas
production
community.
(165)
We
failed
to
recognize
the
number
of
small
facilities
subject
to
the
rule.
(L17)

Regulatory
Flexibility
Act.
The
proposed
rule
would
substantially
impact
small
facilities,
and
we
should
therefore
perform
a
Regulatory
Flexibility
Analysis
(RFA).
(28,
58,
59,
101,
113,
127,
165,
L15)
Our
Regulatory
Flexibility
Act
certification
ignores
the
proposed
rule's
impacts
on
many
small
shipyards,
which
qualify
as
small
businesses.
(45)
The
305
proposed
requirements
would
have
a
substantial
economic
impact
on
the
Ohio
oil
and
gas
producing
industry.
We
conducted
an
inadequate
economic
analysis
of
the
economic
impact
upon
small
entities.
Our
analysis
disregards
the
Regulatory
Flexibility
Act
requirements.
(58)
We
need
to
perform
an
RFA
if
the
proposed
rules
apply
to
owners
or
operators
of
small
aboveground
storage
tanks.
(65)

Secondary
containment.
The
potential
danger
from
a
small
spill
is
insignificant
compared
to
the
burden
imposed
on
small
operations.
(149)
This
regulation
is
an
unwarranted
financial
burden
for
owners
or
operators
of
small
aboveground
tanks
facilities
with
secondary
containment.
(L17)

Small
entity.
Our
method
of
defining
small
entity
led
to
an
inconsistency
with
the
intent
of
the
Regulatory
Flexibility
Act.
We
originally
applied
the
eligibility
requirements
for
Small
Business
Administration
(SBA)
assistance
to
define
small
entity,
and
that
when
we
excluded
this
method
in
favor
of
another,
our
actions
were
inconsistent
with
the
intent
of
the
Regulatory
Flexibility
Act.
(58)
Appalachian
Producers
could
classify
as
small
entities
under
the
Regulatory
Flexibility
Act.
(101)

Response:
Costs.
We
disagree
with
the
commenters
who
stated
that
the
proposed
rule
would
substantially
impact
small
businesses.
We
conducted
a
small
business
screening
analysis
that
we
included
with
the
EIA
(January
1991).
The
purpose
of
conducting
this
small
business
analysis
was
to
determine
if
a
formal
RFA
would
be
required.

In
determining
whether
a
rule
has
a
significant
economic
impact
on
a
substantial
number
of
small
entities,
the
impact
of
concern
is
any
significant
adverse
economic
impact
on
small
entities,
since
the
primary
purpose
of
the
regulatory
flexibility
analyses
is
to
identify
and
address
regulatory
alternatives
"which
minimize
any
significant
economic
impact
of
the
proposed
rule
on
small
entities."
5
U.
S.
C.
Sections
603
and
604.
Thus,
an
agency
may
certify
that
a
rule
will
not
have
a
significant
economic
impact
on
a
substantial
number
of
small
entities
if
the
rule
relieves
regulatory
burden,
or
otherwise
has
a
positive
economic
effect
on
all
of
the
small
entities
subject
to
the
rule.
This
rule
will
significantly
reduce
regulatory
burden
on
all
facilities,
particularly
small
facilities.
For
example,
the
rule
exempts
the
smallest
facilities
from
its
scope.
It
also
gives
all
facilities
greater
flexibility
in
recordkeeping
and
other
paperwork
requirements.
Finally,
it
gives
small
businesses
and
all
other
facilities
the
flexibility
to
use
alternative
methods
to
comply
with
the
requirements
of
the
rule
if
the
facility
explains
its
rationale
for
nonconformance
and
provides
equivalent
environmental
protection.
We
have
therefore
concluded
that
today's
final
rule
will
relieve
regulatory
burden
for
all
small
entities.
After
considering
the
economic
impacts
of
today's
final
rule
on
small
entities,
we
believe
that
this
rulemaking
will
not
have
a
significant
economic
impact
on
a
substantial
number
of
small
entities.

Regulatory
Flexibility
Act.
An
RFA
is
not
required
if
the
rule
will
not
cause
significant
adverse
economic
impacts
on
a
substantial
number
of
small
entities,
which
is
what
the
small
business
analysis
concluded.
To
make
this
determination,
we
evaluated
baseline
and
post­
compliance
financial
ratios
for
typical
small
firms
to
evaluate
the
potential
for
adverse
impacts
of
bankruptcy.
We
evaluated
four
different
ratios
for
firms
in
24
different
306
industry
categories.
Only
one
of
these
ratios
identified
impacts
­­
the
ratio
that
assessed
the
proportionate
impact
to
small
entities
compared
to
larger
entities.
For
six
of
our
24
industries,
the
ratio
estimated
that
small
entities
could
be
affected
in
a
manner
disproportionate
to
the
impact
on
larger
entities.
However,
the
remaining
three
financial
ratio
tests
showed
no
significant
impact
to
these
industries.
As
a
result,
we
believe
we
were
correct
to
state
that
the
rule
would
not
have
a
significant
impact
on
a
substantial
number
of
small
entities.
We
arrived
at
the
same
conclusion
for
the
final
rule
as
we
have
included
many
other
revisions
from
the
1997
proposed
rulemaking
that
are
designed
to
eliminate
many
of
the
smaller
facilities
from
the
rule
as
well
as
to
reduce
the
overall
burden
to
those
facilities
that
remain
regulated
under
the
final
rule.

The
compliance
costs
used
to
estimate
post­
compliance
financial
ratios
reflected
both
the
one­
time
and
recurring
costs
that
we
estimated
in
the
1991
Economic
Analysis,
which
we
added
together
to
calculate
the
maximum
estimated
first­
year
burden
imposed
by
compliance.
If
a
firm
was
not
adversely
impacted
in
the
first
year
­­
when
both
the
onetime
and
annual
recurring
costs
occurred
­­
we
assumed
that
it
would
not
be
subject
to
a
significant
adverse
economic
impact
in
subsequent
years.

We
also
disagree
with
the
comment
that
we
failed
to
assess
the
rule's
potential
impact
on
small
shipyards.
We
estimated
several
different
financial
impacts
for
numerous
facility
types
manufacturing
transportation
equipment
(SIC
37).
Ship
building
and
repairing
is
a
subset
of
this
industrial
category
(SIC
373)
and
thus,
was
captured
by
our
analysis.

Secondary
containment.
Although
we
characterized
the
proposed
72­
hour
impermeability
standard
as
a
baseline,
we
have
not
adopted
this
standard
in
the
final
rule.
We
have
retained
the
current
standard
which
states
that
dikes,
berms,
and
oil
retaining
walls
must
be
sufficiently
impervious
to
contain
oil,
which
more
accurately
reflects
current
industry
standards
and
practices.
We
also
note
that
several
industry
standards
exist
concerning
loading
areas
(e.
g.,
API
2610)
and
that
the
final
rule
merely
clarifies
existing
SPCC
requirements.

Small
entity.
As
described
in
the
Economic
Analysis
for
the
final
rule,
we
are
using
SBA
definition
of
small
entity.
Recently,
the
categorization
of
the
SBA
definitions
was
revised
to
correspond
to
the
North
American
Industry
Classification
System
(NAICS)
rather
than
SIC
codes.
This
change
does
not
affect
the
SPCC
analysis
because
for
the
most
part,
the
definitions
that
applied
to
facilities
based
on
SIC
codes
also
apply
to
facilities
that
are
based
on
NAICS
codes,
and
have
the
same
thresholds
for
determining
if
the
facility
is
a
small
business.

XVI
­
C:
Use
of
incorrect
data
Comments:
Disagree
with
our
use
of
the
SBA's
FINSTAT
database
to
create
a
financial
analysis
of
the
crude
oil
and
natural
gas
industries.
The
database
contains
business
financial
information
collected
between
1976
and
1983
­­
the
zenith
of
the
petroleum
crude
and
natural
gas
production
industry
­­
and
that
simply
adjusting
the
data
for
inflation
does
not
accurately
capture
the
industry
changes
following
that
period.
(58,
128)
307
We
should
reject
the
EIA
because
the
document's
compliance
costs
estimates
are
different
than
those
in
the
Supplemental
Cost
and
Benefit
Analysis.
We
should
have
revisited
the
EIA
using
the
new
estimates
to
determine
if
the
proposed
rule
would
have
a
significant
impact
on
small
entities.
(58)

Response:
We
recognized
the
limitations
of
SBA's
FINSTAT
data
in
our
1991
Small
Business
Analysis.
However,
we
relied
on
the
data
to
perform
our
analysis
because
at
the
time,
it
represented
the
largest,
publicly
available
database
with
financial
information
on
small,
privately
held
firms.
We
also
chose
to
conduct
our
analysis
using
a
different
definition
of
small
business
than
that
used
by
the
SBA
in
order
to
better
estimate
the
proposed
rule's
impacts
on
the
smallest
of
the
small
businesses.
Had
we
used
the
SBA's
definition,
we
would
have
included
in
the
analysis
over
90
percent
of
the
firms
in
the
affected
SICs.
As
a
result,
the
analysis
would
have
been
skewed
to
estimate
the
effects
on
the
larger
of
the
small
businesses,
which
presumably
would
have
more
resources
and
would
be
less
impacted
by
the
proposed
revisions.
By
concentrating
on
the
smallest
of
the
small
businesses,
we
were
better
able
to
determine
the
effects
that
the
proposed
rule
would
have
on
small
firms.

We
have
always
treated
these
provisions
as
requirements
and
thus
as
part
of
baseline
expenditures
by
regulated
firms.
For
the
most
part,
small
facilities
should
experience
a
reduction
in
compliance
burden
due
to
the
rise
in
the
regulatory
threshold,
new
formatting
options,
and
flexibility
to
use
alternative
methods.

XVI
­
D:
Miscalculation
of
costs
Comments:
Agriculture.
The
proposed
rule
would
impose
a
substantial
burden
on
the
agriculture
industry,
and
therefore
the
industry
deserves
special
consideration.
The
proposed
rule
overlaps
with
other
regulations.
(139)

Appalachian
and
Ohio
producers.
The
proposed
regulatory
changes
would
significantly
impact
small
oil
and
gas
producers
in
the
Appalachian
Basin
by
regulating
almost
all
tankage
in
existence,
increasing
the
number
of
facilities
regulated,
increasing
the
extent
and
complexity
of
spill
contingency
plans,
and
requiring
the
implementation
of
new
and
expanded
construction
and
operations
provisions.
(28)
The
proposed
revisions
will
dramatically
impact
Ohio
oil
and
natural
gas
producers.
(58,
59,
70)
The
proposed
revisions
will
pose
severe
and
unique
economic
hardships
to
Appalachian
Producers.
(101,
113)
The
proposed
rule's
benefits
do
not
match
the
costs
for
producers
in
the
Appalachian
Basin,
and
we
should
regulate
only
facilities
storing
large
amounts
of
oil,
and
not
smaller
oil
and
gas
producers.
The
regulatory
changes
will
cause
a
large
percentage
of
oil
and
gas
wells
in
the
area
to
cease
operations.
(165)

Compliance.
The
small
business
impact
analysis
and
the
EIA
cost
estimates
are
sensitive
to
assumptions
of
existing
compliance.
When
we
relax
this
assumption
in
the
SBA,
compliance
costs
increase
substantially.
(182)
308
Costs:
PEs,
mandatory
requirements,
reliance
on
dispersants.
Our
economic
analysis
does
not
truly
represent
the
costs
to
the
regulated
community,
because
we
did
not
properly
analyze
the
following
requirements:
the
specific
Professional
Engineer
(PE)
provision
found
in
§112.3(
d),
the
mandatory
requirements
for
medium
and
large
facilities;
and
the
§112.7(
d)(
1)
contingency
Plan
prohibition
on
reliance
on
dispersants.
(L27)

Definitions:
navigable
waters,
discharge.
We
have
severely
underestimated
the
economic
impact
on
part
112
facilities
because
the
definitions
of
navigable
waters
and
discharge
have
changed
drastically
since
SPCC
guidelines
were
first
implemented.
(28)

Facility
notification.
The
proposed
notification
form
would
pose
a
greater
amount
of
burden
for
facility
owners
or
operators
than
we
estimated.
Outside
persons
­­
such
as
outside
contractors
or
upper
management
­­
would
be
needed
to
complete
the
form.
The
burden
would
be
substantially
greater
for
those
facilities
without
SPCC
Plans.
(34,
48,
187,
189)

Hours
burden.
Our
hours
burden
estimate
of
five
to
10
hours
per
year
is
too
low,
and
estimates
industry
burden
to
be
about
144
hours
per
facility
­­
40
hours
per
year
to
comply
with
the
regulation,
40
hours
to
prepare
a
training
program,
40
hours
to
prepare
training
program
materials,
and
24
hours
for
employee
training.
(35)
Appalachian
facilities
would
incur
a
greater
hours
burden
than
our
estimates
because
such
facilities
are
remote
and
widely
dispersed.
(59)

Secondary
containment.
Our
industry
cost
estimate
for
the
proposed
regulations
­­
of
$441
million
in
the
first
year
and
$71.8
million
each
subsequent
year
­­
is
erroneously
low.
(28,
31,
36,
58,
113,
165)
Comrnenters
came
to
this
conclusion
by
calculating
compliance
cost
estimates
for
the
following
requirements:
72­
hour
impermeability
for
secondary
containment
and
diked
areas,
and
installation
of
containment
systems
at
all
truck
loading
locations.
(28,
165)
The
majority
of
owners
or
operators
would
have
to
modify
or
recertify
Plans
to
meet
the
proposed
regulatory
changes.
(36)
The
true
compliance
costs
are
at
least
$892
million,
as
we
estimated
in
the
Supplemental
Cost
and
Benefit
Analysis.
(58)
Due
to
the
financial
burden,
we
should
not
require
owners
or
operators
of
aboveground
tank
facilities
with
secondary
containment
and
total
storage
capacity
of
less
than
10,000
gallons
to
develop
a
Plan.
(L17)

Small
business.
The
proposed
revisions
would
have
a
severe
economic
impact
on
small
businesses
throughout
the
country.
(50,
58,
110,
139,
182)
The
proposed
rule
imposes
on
small
facilities
a
disproportionately
high
level
of
costs
as
compared
to
environmental
benefits,
because
such
facilities
pose
a
relatively
small
risk
of
spills.
(62,
125,
156)

Small
discharges.
The
regulation
is
costly
and
unnecessary,
and
we
have
not
established
that
problems
even
exist
with
discharges
from
small
crude
oil
production
facilities.
Consequentially,
we
should
gather
up­
to­
date,
realistic
data
to
make
an
informed
decision.
(101)
309
Stripper
operations.
The
proposed
revisions
would
cause
many
small
stripper
operations
to
go
out
of
business.
(110)
The
rule
disproportionately
impacts
small
entities

specifically
stripper
operations
­­
relative
to
medium
and
large
entities,
because
the
Petroleum
Extraction
Industry's
compliance
cost
to
sales
comparison
impact
is
nearly
twice
as
high
as
other
industry's,
and
exceeds
the
110
percent
ratio.
(L27)

Training.
We
should
clarify
which
category
of
individuals
must
receive
mandatory
training,
because
as
the
rule
is
currently
written,
the
economic
analysis'
cost
estimate
for
training
is
insufficient.
(45)

Response:
Agriculture.
Our
Small
Business
Analysis
also
considered
impacts
to
small
farmers,
by
analyzing
small
firms
in
SIC
1
(agricultural
crop
production)
and
SIC
2
(agricultural
livestock
production).
For
both
SIC
Codes,
we
estimated
that
the
proposed
rule
would
have
an
insignificant
impact
on
these
entities.
We
arrived
at
a
similar
conclusion
for
the
final
rule,
as
we
have
adopted
few
new
requirements
and
have
provided
a
de
minimis
exemption.
In
addition,
we
are
no
longer
regulating
the
smallest
facilities.
We
have
also
adopted
a
number
of
provisions
designed
to
reduce
the
overall
burden
for
the
remaining
regulated
facilities,
which
includes
eliminating
overlap
with
other
Federal
requirements
(e.
g.,
UST
requirements,
flexibility
in
Plan
formatting).

Appalachian
and
Ohio
producers.
We
considered
the
potential
impacts
on
small
firms
in
our
Small
Business
Analysis.
In
our
analysis
of
SIC
131,
crude
oil
and
natural
gas
production,
we
determined
that
small
firms
in
this
industry
were
unlikely
to
close
as
a
result
of
the
compliance
costs
associated
with
the
proposed
rule.
However,
these
firms
may
experience
disproportionate
impacts
compared
to
larger
firms.
In
the
final
rule,
we
introduced
a
de
minimis
storage
capacity,
which
may
benefit
a
number
of
the
smaller
oil
production
firms.
For
the
firms
that
remain
in
the
SPCC
program,
we
are
finalizing
a
rule
that
promotes
flexibility
and
has
few
new
requirements.
As
a
result,
we
believe
that
most
oil
and
gas
production
firms
will
experience
roughly
a
40
percent
reduction
in
burden
and
costs
over
time.

Compliance.
In
response
to
the
comment
that
our
analysis
hinges
on
our
assumption
of
existing
compliance,
we
note
that
our
assumption
of
a
baseline
of
full
industry
compliance
is
consistent
with
OMB
guidelines
for
preparing
regulatory
impact
analyses.
We
produced
a
Supplemental
Analysis
to
estimate
the
cost
of
certain
provisions
of
the
proposed
rule
under
the
assumption
that
a
number
of
owner
or
operators
have
interpreted
the
proposed
changes
as
substantive
changes
in
their
duties
to
comply
with
this
regulation.
The
commenter
is
correct
to
point
out
that
as
a
result
of
the
relaxed
assumptions
concerning
baseline
activities,
estimated
compliance
costs
increased.
In
the
final
rule,
we
have
decided
not
to
adopt
many
of
the
proposed
revisions
that
would
have
added
to
the
baseline
compliance
costs
for
facilities
(e.
g.,
notification).
We
also
are
providing
a
number
of
revisions
in
the
final
rule
designed
to
decrease
the
overall
compliance
burden
to
regulated
facilities
as
well
as
to
offer
facilities
increased
flexibility
to
meet
their
obligations
under
the
rule.

Costs:
PEs,
mandatory
requirements,
and
reliance
on
dispersants.
310
Dispersants.
In
1991,
under
§112.7(
d)(
1),
we
proposed
language
clarifying
the
contents
of
an
appropriate
oil
spill
contingency
plan.
We
omitted
the
reference
to
40
CFR
part
109
and
instead,
specified
basic
requirements
for
an
oil
spill
contingency
plan.
However,
in
the
final
rule,
we
did
not
adopt
the
proposed
language
and
instead
retained
the
existing
reference
to
40
CFR
part
109.

Mandatory
requirements.
We
disagree
that
we
ignored
mandatory
requirements
in
our
economic
analysis
for
medium
and
large
facilities.
We
provided
cost
estimates
in
the
economic
analysis
for
small,
medium,
and
large
facilities.
We
discussed
every
proposed
revision
and
noted
its
effect
on
the
regulated
community
in
the
analysis.
We
did
not
propose
nor
did
we
finalize
any
requirements
that
are
dependent
on
facility
size.

PEs.
Final
§112.3(
d)
does
not
contain
a
State
specific
certification
requirement
for
PEs,
because
the
SPCC
program
is
national
in
scope
and
therefore
State
expertise
is
not
necessary.

Definitions:
navigable
waters,
discharge.
We
have
made
very
little
substantive
change
to
the
definitions
of
navigable
waters
and
discharge
since
1973.
The
new
definition
of
navigable
waters
adds
clarity
and
more
examples,
and
is
now
consistent
with
other
regulatory
definitions
of
the
term.
The
new
definition
of
discharge
was
made
consistent
with
the
Clean
Water
Act
definition
as
amended
in
1978,
which
exempted
certain
discharges
associated
with
NPDES
permits.
This
change
would
not
result
in
an
increase
in
economic
impact
­­
rather,
some
facilities
will
no
longer
be
regulated
as
a
result
of
the
revised
definition
because
they
are
no
longer
expected
to
discharge
oil,
leading
to
a
decrease
in
economic
impact.
In
any
case,
any
change
in
economic
impact
due
to
this
definition
revision
is
the
result
of
the
change
to
the
statute.

Facility
notification.
We
have
decided
to
withdraw
the
proposed
facility
notification
requirement
because
we
are
still
considering
issues
associated
with
establishing
a
paper
versus
electronic
notification
system,
including
issues
related
to
providing
electronic
signatures
on
the
notification.
Should
the
Agency
in
the
future
decide
to
move
forward
with
a
facility
notification
requirement,
we
will
repropose
such
requirement.

Hours
burden.
We
have
adopted
a
model
facility
approach
in
estimating
the
approximate
hours
burden
for
facilities
to
comply
with
the
rule.
We
adopted
this
approach
to
better
characterize
the
diverse
universe
of
regulated
facilities.
We
developed
eight
different
model
facilities
for
this
rulemaking
–
which
we
designed
to
represent
the
typical
facility
in
each
category
­­
based
on
oil
storage
capacity
and
primary
use
of
oil.
We
acknowledge
that
some
facilities
may
experience
a
higher
hours
burden
and
cost
for
select
activities.
However,
on
average,
we
believe
that
the
hours
burden
and
cost
incurred
by
our
eight
different
model
facilities
adequately
characterize
the
approximate
burden
to
other
facilities
with
similar
characteristics.

Secondary
containment.
We
disagree
with
the
commenters
who
asserted
that
we
underestimated
the
cost
to
comply
with
the
secondary
containment
and
truck
loading
area
311
requirements.
We
noted
in
our
1991
economic
analysis
that
we
considered
these
costs
as
part
of
the
baseline
cost
of
compliance,
which
are
not
affected
by
the
proposed
rule.
In
response
to
an
OMB
comment,
we
later
costed
out
these
provisions
in
a
supplemental
analysis.
In
that
analysis,
we
estimated
that
78
percent
and
88
percent
of
the
regulated
community
were
already
in
compliance
with
these
requirements,
respectively,
and
would
not
be
affected
by
the
proposed
rule
change.

Since
we
last
performed
these
analyses,
API
has
issued
several
industry
standards,
including
API
653
and
2610,
which
address
many
of
the
provisions
in
the
SPCC
rule.
As
a
result,
the
final
rule
relies
on
current
industry
standards
and
practices,
where
feasible.
In
the
final
rule,
we
withdrew
the
proposed
72­
hour
impermeability
standard
for
secondary
containment
and
maintained
the
current
requirement
that
dikes,
berms,
and
oil
retaining
walls
must
be
sufficiently
impervious
to
contain
oil.
As
a
result,
the
final
rule
reflects
current
industry
standards
and
poses
no
additional
requirements
on
industry.

Small
business.
We
disagree
that
we
failed
to
analyze
the
impact
of
the
proposed
revisions
on
small
businesses.
We
direct
the
commenter
to
the
1991
Small
Business
Analysis
that
is
appended
to
the
Economic
Analysis
wherein
we
analyze
the
effects
of
the
rule
on
small
business.
We
also
disagree
that
costs
would
be
disproportionately
high
for
small
facilities
compared
to
the
benefits.
Although
our
small
business
analysis
did
identify
that
small
facilities
in
some
industries
could
be
disproportionately
affected,
in
no
instances
did
it
show
that
these
facilities
would
be
significantly
impacted.
We
expect
the
impact
of
the
final
rule
will
be
less
than
we
originally
estimated
because
we
have
incorporated
several
changes
to
reduce
the
overall
compliance
burden
(for
example,
the
rise
in
regulatory
threshold
­
see
§112.1(
d)(
2)(
ii)).
Also,
to
calculate
total
aboveground
storage
capacity,
a
facility
owner
or
operator
need
only
count
containers
greater
than
55
gallons.
The
de
minimis
capacity
will
eliminate
from
the
rule
the
smallest
of
the
regulated
facilities.
We
believe
that
the
cost
of
compliance
for
smaller
facilities
will
be
less
than
that
for
larger
facilities
because
smaller
facilities
are
generally
less
complex
than
larger
facilities.
As
a
result,
it
will
take
less
effort
to
prepare
and
implement
a
Plan.
The
supporting
analyses
for
the
final
rule
provides
more
detailed
explanations
of
our
assumptions
concerning
this
issue.

Small
discharges.
A
small
discharge
may
have
a
harmful
environmental
effect.
Therefore,
small
production
facilities
need
prevention
measures
to
avert
costly
discharges.
Recent
analysis
confirms
this
statement.
See
the
Denial
of
petition
requesting
amendment
of
the
Facility
Response
Plan
rule,
62
FR
54508
et
seq.,
October
20,
1997.

Stripper
operations.
We
disagree
that
the
rule
would
have
an
adverse
economic
impact
on
stripper
wells.
We
specifically
analyzed
the
impact
that
the
rule
would
likely
have
on
small
businesses
involved
in
crude
oil
and
natural
gas
extraction
(SIC
131).
In
conducting
our
closure
analysis,
we
looked
specifically
at
three
financial
ratios
­­
return
on
assets,
total
debt
to
total
assets,
and
compliance
costs
to
net
sales.
These
tests
failed
to
indicate
that
small
firms
in
SIC
131
would
be
significantly
impacted.
We
did
find,
however,
that
small
firms
in
SIC
131
may
experience
disproportionate
impacts
compared
to
larger
firms
in
their
industry.
This
was
recognized
in
the
Small
Business
Analysis.
312
Training.
In
the
final
rule,
we
have
clarified
the
language
regarding
training
requirements
to
apply
only
to
oil­
handling
personnel.
See
§112.7(
f).
We
have
not
provided
a
cost
estimate
for
this
requirement,
because
we
have
always
required
a
facility
owner
or
operator
to
provide
adequate
training
for
facility
personnel.
The
final
rule
merely
clarifies
that
an
owner
or
operator
does
not
need
to
train
all
personnel
­­
only
oil­
handling
personnel.

XVI
­
E:
Additional
costs
Comments:
Baseline
costs.
Changing
the
regulatory
language
from
should
to
shall
will
impose
additional
costs
on
part
112
facilities.
(45,
113,
125,
L27)
Electrical
utilities
industry
must
perform
substantial
construction
as
a
result
of
the
changes.
These
changes
are
impracticable
and
unnecessary
to
address
any
reasonable
risk
of
discharge
at
electrical
facilities.
(125)
We
incorrectly
assume
that
many
facilities
are
already
in
full
compliance
with
industry
standards,
and
that
we
should
not
consider
this
scenario
as
the
baseline.
(L27)

Impermeability
requirements.
We
should
not
require
owners
or
operators
of
Appalachian
Production
facilities
to
meet
the
impermeability
standards
due
to
the
limited
environmental
benefit
and
high
associated
costs.
(101)
We
did
not
address
in
the
analyses
two
specific
requirements
in
the
proposed
revisions
­­
the
requirements
for
containment
systems
and
diked
areas
to
be
impervious
to
oil
for
72
hours.
These
requirements
would
require
significant
capital
expenditures
for
many
facility
owners
or
operators.
(182)

Paperwork
Reduction
Act.
The
time
estimates
we
listed
in
the
Paperwork
Reduction
Act
certification
are
erroneous,
and
too
low.
(45)

PEs.
Requiring
an
independent
or
outside
PE
for
Plan
certification
would
be
extremely
expensive
for
facilities
located
in
remote
areas.
(59,
65)
Requiring
the
use
of
an
independent
or
outside
PE
would
be
incredibly
burdensome
to
facility
owners
or
operators.
(59,
67,
110,
187)
Discussions
with
a
PE
concerning
the
use
of
alternative
measures
are
not
negligible
costs.
Regarding
the
EIA,
we
should
not
have
included
as
a
benefit,
the
requirement
for
a
PE
to
have
no
financial
interest
in
the
facility
because
it
was
not
included
in
the
proposed
revisions.
(L27)

Regular
inspection
of
storage
tanks.
Requiring
regular
inspection
of
storage
tanks
would
impose
a
significant
burden
on
facility
owners
or
operators.
(65)

Vacuum
protection,
equalizing
lines,
reinstallation
of
dike
drains.
Asks
us
to
clarify
whether
we
had
included
the
cost
of
vacuum
protection
installation
into
the
cost
analysis.
(31,
101,
L15)
Asks
us
to
clarify
that
we
had
included
the
cost
of
equalizing
lines
installation
as
specified
in
§112.9(
d)(
4)(
ii)
into
the
cost
analysis.
(101)
We
should
include
in
the
economic
analyses
the
cost
of
reinstalling
tank
dike
drains
as
required
in
§112.9(
c),
because
owners
or
operators
of
facilities
have
removed
over
100,000
forewall
drains
as
a
result
of
the
part
112
rules
of
1973.
(L27)
313
Weight
restrictions.
We
failed
to
recognize
the
substantial
costs
to
owners
or
operators
of
determining
accurate
weight
restrictions.
(76)

Response:
Baseline
costs.
We
note
that
we
only
costed
out
in
our
analysis
the
incremental
effects
associated
with
the
proposed
regulatory
changes.
We
did
not
determine
the
costs
of
complying
with
the
existing
rule.
We
have
always
accounted
for
these
requirements
in
the
information
collection
burden
estimates
for
the
rule,
and
have
always
assumed
100
percent
compliance
by
the
regulated
community.
Consequently,
because
we
are
merely
clarifying
in
the
final
rule
what
is
already
required
of
the
regulated
community
and
because
we
have
accounted
for
these
costs
in
our
continuing
analyses
of
the
program,
we
have
treated
these
costs
as
baseline
in
the
analyses
supporting
this
rulemaking.

Impermeability
requirements.
We
withdrew
the
proposed
72­
hour
requirement.
We
are
maintaining
the
extant
requirement
that
dikes,
berms,
and
oil
retaining
walls
must
be
sufficiently
impervious
to
contain
oil.
Therefore,
there
are
no
incremental
costs.
The
revised
rule,
like
the
current
rule,
does
not
require
a
specific
impermeability
for
dikes
and
does
not
require
a
specific
method
of
secondary
containment
at
loading
areas,
and
this
flexibility
is
reflected
in
our
cost
estimates.

Paperwork
Reduction
Act.
To
estimate
the
burden,
we
used
estimates
based
on
an
engineering
approach
assuming
certain
small
facility
characteristics.
We
note
that
the
actual
burden
for
individual
facilities
may
be
greater
or
less
than
twelve
hours,
but
consider
this
estimate
to
be
a
fair
assumption
for
the
average
facility.

PEs.
These
commenters
were
principally
concerned
that
we
did
not
fully
account
for
the
cost
to
a
facility
owner
or
operator
for
a
PE
to
visit
each
facility
before
certifying
a
Plan.
We
note
that
we
did
not
propose
this
requirement,
but
requested
comments
on
it.
In
the
final
rule,
we
require
either
the
PE
or
the
PE's
agent
to
visit
and
examine
the
facility
before
the
PE
certifies
the
Plan.
An
agent
might
include
an
engineering
technician,
technologist,
graduate
engineer,
or
other
qualified
person
to
prepare
preliminary
reports,
studies,
and
evaluations
after
visiting
the
site.
The
PE,
after
reviewing
the
agent's
work,
could
then
legitimately
certify
the
Plan.
Also,
in
the
final
rule,
we
allow
the
PE
to
be
an
employee
of
the
facility
as
well
as
registered
in
a
different
State
than
the
facility
is
located,
in
order
to
approve
a
Plan.
The
rationale
is
that
SPCC
work
is
national
in
scope
and
therefore
State
expertise
is
unnecessary.

We
disagree
that
the
burden
for
a
PE
to
discuss
a
deviation
in
a
Plan
is
an
incremental
cost.
Under
the
current
rule,
the
PE
has
the
same
flexibility
in
the
application
of
good
engineering
practice.
Therefore,
such
discussion
is
a
baseline
activity.

Although
we
did
not
propose
in
1991
that
the
certifying
PE
have
no
direct
financial
ties
to
the
facility,
we
note
that
we
requested
comments
regarding
this
issue.
In
any
event,
we
did
not
adopt
such
a
provision
in
the
final
rule,
and
note
that
the
benefits
of
the
final
rule
do
not
include
any
consideration
of
whether
the
PE
has
a
financial
interest
in
the
facility.
314
Regular
inspection
of
storage
tanks.
Regular
inspection
of
storage
containers
is
already
required
under
the
current
rule.
Therefore,
it
is
a
baseline
cost
and
not
an
incremental
effect
of
the
final
rule.

Reinstallation
of
dike
drains.
We
disagree
that
we
should
include
in
the
economic
analyses
the
cost
of
reinstalling
tank
dike
drains
because
neither
the
current
rule
nor
the
final
rule
requires
such
reinstallation.

Vacuum
protection,
equalizing
lines.
Vacuum
protection
and
overflow
equalizing
lines
are
measures
an
owner
or
operator
must
consider
under
the
current
rule.
Our
economic
analyses
only
costed
out
the
incremental
effects
of
the
proposed
rule,
not
the
existing
rule's
requirements.
Therefore,
we
considered
the
cost
associated
with
these
activities
as
a
baseline
cost
and
we
did
not
include
them
in
our
economic
analyses.

Weight
restrictions.
We
have
deleted
the
proposed
recommendation
concerning
weight
restrictions.
Therefore,
there
are
no
incremental
costs
to
the
owner
or
operator.

XVI
­
F:
Costs
to
the
electric
utility
industry
Comments:
Costs.
Our
compliance
costs
for
the
electric
utility
industry
are
erroneously
low.
Owners
or
operators
of
electrical
equipment
storing
10,000
gallons
of
oil
or
less
should
not
be
subject
to
the
SPCC
requirements
because
such
equipment
poses
a
small
amount
of
environmental
risk.
(125)
We
failed
to
consider
the
impact
of
the
rule
on
electrical
substations
and
installations
in
the
current
Regulatory
Impact
Analysis
(RIA).
As
a
result,
the
cost
of
compliance
cited
in
the
RIA
is
erroneously
low.
We
should
prepare
a
new
RIA
that
accurately
reflects
the
impact
of
the
rule
on
electric
utilities.
(130)
It
would
be
costly
and
time­
consuming
to
comply
with
the
SPCC
regulations
for
facilities
with
electrical
equipment.
(41,
184,
189)

High
viscosity.
We
should
exclude
from
the
proposed
secondary
containment
provisions
and
integrity
testing
requirements
bulk
storage
tanks
that
hold
high
viscosity
petroleum
products.
We
should
not
require
integrity
testing
and
secondary
containment
for
high
pour
point
bulk
storage
containers,
and
we
did
not
analyze
the
costs
associated
with
the
proposed
requirement.
(125)

Impact.
If
electrical
equipment
is
subject
to
SPCC
regulations,
then
the
number
of
covered
utility
industry
facilities
would
increase
substantially
and
the
rule
would
have
a
greater
impact
on
the
electric
utility
industry
than
we
anticipated.
(125,
189)

Regulatory
alternatives.
In
order
to
comply
with
the
proposed
rules,
the
electric
utility
industry
faces
significantly
higher
costs
than
we
estimated,
yet
the
industry
poses
an
insignificant
environmental
risk.
The
commenter
provided
cost
estimates
for
the
electric
utility
industry
to
comply
with
the
following
requirements:
constructing
secondary
containment
and
drainage
systems;
testing
tanks
for
integrity;
complying
with
the
impermeability
requirement;
and
writing
and
implementing
Plans
at
substations.
Because
of
these
costs,
the
commenter
suggested
the
following
alternatives:
315
°
State
that
electrical
equipment
is
not
be
subject
to
SPCC
regulations.
°
Modify
the
SPCC
risk
criteria
to
ensure
that
only
the
facilities
which
pose
a
real
risk
of
harm
are
covered
by
the
program.
°
Address
specific
elements
of
the
proposal
that
are
impracticable
or
impose
undue
costs
for
the
avoided
risk
as
applied
either
to
electrical
equipment
or
tanks.
(125)

Response:
Cost,
impact,
regulatory
alternatives.
We
disagree
that
it
would
be
costly
for
facilities
with
electrical
equipment
to
comply
with
the
SPCC
regulation,
and
that
subjecting
electrical
equipment
to
the
regulations
would
have
a
greater
impact
on
the
electric
utility
industry
than
we
anticipated.
Such
facilities
must
only
comply
with
requirements
for
oilfilled
electrical
equipment,
and
have
considerable
flexibility
in
doing
so.
Furthermore
we
have
exempted
the
smallest
containers
and
facilities
from
the
rule.
Therefore,
costs
will
be
mitigated.

In
our
analysis
of
the
effects
of
the
proposed
and
final
rule,
we
incorporated
a
model
facility
approach.
We
estimated
the
costs
of
complying
with
the
incremental
effects
of
the
proposed
and
final
rule
changes
based
on
the
characteristics
assigned
to
these
model
facilities.
In
reality,
some
facilities
may
incur
greater
costs,
while
other
facilities
incur
lower
costs.
Since
the
1991
rule
was
proposed,
we
have
redefined
our
treatment
of
electric
utilities
to
reflect
the
slightly
greater
burden
that
they
may
incur
to
comply
with
this
rule.
This
change
was
incorporated
in
1997,
in
response
to
industry
comments
concerning
our
Information
Collection
Request
renewal
activities
for
the
SPCC
program.
We
also
note
that
many
of
the
estimates
provided
by
the
commenters
are
not
associated
with
the
proposed
revisions,
and
we
already
require
facilities
to
consider
or
implement
many
of
these
activities.

We
note,
however,
that
the
final
rule
provides
increased
flexibility
for
an
owner
or
operator.
In
fact,
many
of
the
changes
reduce
the
overall
burden
to
electrical
utilities.
We
clarify
in
the
final
rule
that
electrical
equipment
is
subject
only
to
the
general
SPCC
requirements,
and
not
the
more
specific
requirements
for
bulk
oil
storage
containers.
Secondary
containment
is
still
required
for
all
facilities
under
§112.7(
c).
If
it
is
not
practicable
for
safety
or
other
valid
engineering
reasons,
under
§112.7(
d),
the
owner
or
operator
may
provide
a
contingency
plan
following
40
CFR
part
109,
and
otherwise
comply
with
the
requirements
of
that
section.
Furthermore,
an
owner
or
operator
may
deviate
from
most
of
the
rule's
substantive
requirements
if
he
explains
his
reasons
for
nonconformance
and
provides
equivalent
environmental
protection.
40
CFR
112.7(
a)(
2).
This
provision
also
cuts
costs.

We
agree
that
any
equivalent
prevention
plan
acceptable
to
the
Regional
Administrator
qualifies
as
an
SPCC
Plan
as
long
as
it
meets
all
Federal
requirements
(including
certification
by
a
Professional
Engineer),
and
is
cross­
referenced
from
the
requirement
in
part
112
to
the
page
of
the
equivalent
plan.
We
do
not
agree
that
we
should
specify
acceptable
formats.
We
give
examples
of
those
acceptable
formats,
but
those
examples
are
not
meant
to
be
exhaustive.
See
the
discussion
on
§112.7(
c)
in
today's
preamble
and
in
this
document.
316
One
example
of
an
equivalent
plan
might
include
a
multi­
facility
plan
for
operating
equipment.
This
type
of
plan
is
intended
for
electrical
utility
transmission
systems,
electrical
cable
systems,
and
similar
facilities
which
might
aggregate
equipment
located
in
diverse
areas
into
one
plan.
Examples
of
operating
equipment
containing
oil
include
electrical
equipment
such
as
substations,
transformers,
capacitors,
buried
cable
equipment,
and
oil
circuit
breakers.

A
general,
multi­
facility
plan
for
operational
equipment
used
in
various
manufacturing
processes
containing
over
the
threshold
amount
of
oil
might
also
be
acceptable
as
an
SPCC
Plan.
Examples
of
operating
equipment
used
in
manufacturing
that
contains
oil
include
small
lube
oil
systems,
fat
traps,
hydraulic
power
presses,
hydraulic
pumps,
injection
molding
machines,
auto
boosters,
certain
metalworking
machinery
and
associated
fluid
transfer
systems,
and
oil
based
heaters.
Whenever
you
add
or
remove
operating
equipment
in
your
Plan
that
will
either
increase
or
decrease
the
potential
for
a
discharge
as
described
in
§112.1(
b),
you
must
amend
your
Plan.

Multi­
facility
plans
would
include
all
elements
required
for
individual
plans.
Site­
specific
information
would
be
required
for
all
equipment
included
in
each
plan.
However,
the
sitespecific
information
might
be
maintained
in
a
separate
location,
such
as
a
central
office,
or
an
electronic
data
base,
as
long
as
such
information
was
immediately
accessible
to
responders
and
inspectors.
If
you
keep
the
information
in
an
electronic
data
base,
you
must
also
keep
a
paper
or
other
backup
that
is
immediately
accessible
for
emergency
response
purposes,
or
for
EPA
inspectors,
in
case
the
computer
is
not
functioning.
Where
you
place
that
site­
specific
information
would
be
a
question
of
allowable
formatting,
as
is
the
question
of
what
is
an
"equivalent"
plan;
an
issue
subject
to
RA
discretion.

Finally,
we
note
that
many
of
the
smaller
substation
facilities
will
be
exempted
from
the
SPCC
regulations
due
to
the
changes
to
§112.1(
d)
in
the
final
rule
–
specifically,
the
introduction
of
a
55
gallon
de
minimis
threshold
as
well
as
the
elimination
of
the
660
gallon
threshold.

High
viscosity.
If
the
owner
or
operator
wishes
to
deviate
from
secondary
containment
requirements,
he
may
only
do
so
because
secondary
containment
is
not
practicable
in
the
application
of
good
engineering
practice.
He
must
also
follow
the
requirements
of
§112.7(
d)
in
such
case.
If
he
wishes
to
deviate
from
integrity
testing
requirements,
he
must
follow
§112.7(
a)(
2).
However,
both
of
these
activities
are
baseline
activities,
and
therefore,
not
incremental
costs.

XVI
­
G:
Miscellaneous
cost
issues
Comments:
Bioremediation.
We
are
incorrect
to
assume
that
Appalachian
producers
would
use
off­
site
disposal
for
remediation,
because
the
high
costs
associated
with
travel
time
and
distance
would
dictate
another
method.
(101)
We
should
specifically
allow
the
use
of
bioremediation
and
on­
site
disposal
following
a
spill
event,
because
of
the
high
costs
associated
with
off­
site
disposal.
(113)
317
External
heating
systems.
Objects
to
the
cost
to
facility
owners
or
operators
of
installing
external
heating
systems.
(76)

Extraction
industry
­
discretionary
provisions.
The
cost
of
the
regulation
is
greater
than
indicated
in
the
economic
analysis,
because
the
petroleum
extraction
industry
is
unable
to
take
advantage
of
the
discretionary
provisions
for
medium
or
large
facilities.
The
petroleum
extraction
industry
is
able
to
take
advantage
of
the
discretionary
training
provision.
(L27)

Farmers.
Farmers
cannot
afford
to
comply
with
the
proposed
regulations,
and
requested
that
we
create
an
exemption
for
farmers
based
on
tank
size
and
risk.
(106)

Insufficient
information.
We
have
provided
insufficient
useful
information
regarding
the
economic
analyses
in
the
preamble
to
the
proposed
rule.
Therefore,
the
public
cannot
understand
or
comment
on
the
proposed
rule.
(110)

Jurisdiction,
wetlands,
sensitive
ecological
areas.
We
should
reflect
in
the
benefit
analysis
our
change
in
jurisdiction
modified
by
EO
12777.
(128)
We
should
clearly
define
the
jurisdiction
of
the
regulation
as
well
as
the
terms
wetlands
and
sensitive
ecological
areas,
because
the
potential
costs
of
the
proposed
regulation
could
be
devastating
for
the
regulated
community.
(139)

Permanently
closed
containers.
We
should
consider
tanks
previously
removed
from
service
as
permanently
closed.
Owners
or
operators
would
have
to
bear
significant
costs
to
permanently
close
tanks
so
the
tanks
will
not
apply
towards
the
storage
capacity
threshold
calculation.
(101)

Recordkeeping
requirements.
Under
§112.9(
d)
and
(e),
we
should
not
require
owners
or
operators
to
retain
inspection
and
test
records
for
five
complete
calendar
years
irrespective
of
ownership,
due
to
the
financial
burden
on
the
facilities.
(113)

Scientific
rationale.
We
need
scientific
justification
for
the
proposed
revisions.
(127,
132,
139,
160,
L27)

Secondary
containment.
Provides
cost
estimates
for
many
elements
of
the
proposed
rule.
(31)
Produces
compliance
estimates
based
on
a
small,
single
facility
common
to
oil
and
gas
production
in
Ohio.
(70)
The
largest
single
cost
to
facilities
is
the
proposed
§112.7(
c)
requirement
that
dikes,
berms,
and
oil
retaining
walls
must
be
sufficiently
impervious
to
contain
oil.
The
commenter
estimated
startup
costs
to
be
$10,425
and
annual
costs
to
be
about
$260
per
facility.
(25,
70)

State
and
local
regulation.
The
proposed
revisions
are
unnecessary
because
State
and
local
agencies
already
regulate
aboveground
storage
tanks.
(127,
139)

Triennial
review.
Questions
our
cost
estimates
regarding
the
triennial
Plan
review
and
evaluation.
The
requirement
would
cost
a
well
operator
$500
for
PE
certification,
and
a
318
tank
battery
operator
$3,000
for
PE
certification.
The
requirement
would
cost
owners
or
operators
of
onshore
production
facilities
$2.
7
million.
(103,
113,
187)

Response:
Bioremediation.
We
agree
with
the
commenter
that
bioremediation
may
be
a
proper
disposal
method.
We
do
not
assume
any
particular
facility
will
use
bioremediation,
but
it
is
an
available
option.

Existing
program.
We
disagree
that
the
revisions
to
the
rule
would
unnecessarily
raise
the
cost
of
compliance
over
the
current
program
because
the
majority
of
the
changes
are
clarifications
of
existing
requirements.
Also,
we
did
not
adopt
all
of
the
proposed
changes,
some
of
which,
like
facility
notification,
would
have
raised
costs.
Further,
the
final
rule
reduces
the
regulatory
burden
by:
reducing
the
total
number
of
facilities
subject
to
the
rule;
introducing
flexibility
in
formatting
and
recordkeeping;
and,
by
encouraging
the
use
of
industry
standards
to
comply
with
SPCC
requirements.

External
heating
systems.
We
deleted
the
proposed
recommendation
to
consider
the
feasibility
of
installing
an
external
heating
system
from
§112.8(
c)(
7).
That
proposed
recommendation
is
currently
a
requirement.
Therefore,
we
have
reduced
costs
for
an
owner
or
operator.

Extraction
industry
­
discretionary
provisions.
The
rule
does
not
prescribe
differing
requirements
for
facilities
merely
based
on
size.
We
have
not
established
discretionary
provisions
for
any
facilities.
All
of
the
rule
provisions
are
mandatory.
However,
an
extraction
facility
may
avail
itself
of
a
deviation
in
the
same
manner
as
any
other
facility.

Farmers.
We
disagree
that
farmers
cannot
afford
to
comply
with
the
rule.
However,
in
the
final
rule,
we
have
raised
the
regulatory
threshold.
We
no
longer
regulate
a
facility
that
stores
660
gallons
or
more
of
oil
in
a
single
aboveground
tank,
so
long
as
the
aggregate
aboveground
storage
capacity
does
not
exceed
1,320
gallons.
We
expect
that
a
significant
number
of
small
facilities
­­
including
farms
­­
will
benefit
from
this
change,
and
expect
the
majority
of
small
facilities
with
a
single
oil
tank
to
no
longer
be
regulated.
We
refer
the
commenter
to
the
supporting
analyses
for
more
specific
estimates
on
the
estimated
impacts.
We
also
exempt
containers
of
less
than
55
gallons
from
all
rule
requirements.

Insufficient
information.
We
disagree
that
we
failed
to
provide
sufficient
information
regarding
the
economic
analysis
in
the
preamble.
We
summarized
the
results
of
the
economic
analyses
therein.
The
economic
analyses
are
available
for
review
in
the
public
docket
for
those
wishing
to
review
more
specific
information
on
the
approach
we
used
to
estimate
our
results.
We
believe
that
many
of
the
commenters
who
were
concerned
about
the
costs
and
benefits
of
the
proposal
will
find
that
the
changes
made
in
the
final
rule
are
to
their
benefit.

Jurisdiction,
wetlands,
sensitive
ecological
areas.
The
applicability
of
the
rule
is
clearly
set
out
in
§112.1.
We
have
added
a
definition
for
wetlands
in
the
final
rule
to
provide
319
clarity
for
the
regulated
community.
We
discussed
sensitive
environments
in
the
final
1994
Facility
Response
Rule.
See
59
FR
34070,
34089,
July
1,
1994.

In
our
analysis
of
the
impact
of
the
final
rule,
we
consider
the
jurisdictional
effects
of
EO
12777
(56
FR
54757,
October
22,
1991).
Section(
b)(
1)
of
EO
12777
delegates
to
the
EPA
authority
in
section
311(
j)(
1)(
C)
relating
to
the
establishment
of
procedures,
methods,
and
equipment,
and
other
requirements
for
equipment
to
prevent
and
to
contain
discharges
of
oil
and
hazardous
substances
from
non­
transportation­
related
onshore
facilities.
Section(
b)(
2)
of
EO
12777
delegates
similar
authority
to
contain
discharges
of
oil
and
hazardous
substances
from
vessels
and
transportation­
related
onshore
facilities
and
deep
water
ports
to
the
Secretary
of
Transportation.
Section(
b)(
3)
of
the
EO
delegates
similar
authority
for
offshore
facilities,
including
associated
pipelines,
other
than
deep
water
ports,
to
the
Secretary
of
the
Interior.
An
MOU
between
EPA,
DOT,
and
DOI,
found
at
Appendix
B
to
part
112,
redelegated
from
DOI
to
EPA
the
responsibility
for
non­
transportation­
related
offshore
facilities
located
landward
of
the
coast
line.
Similarly,
the
MOU
redelegated
from
DOI
to
DOT
the
responsibility
for
transportation­
related
offshore
facilities,
including
pipelines,
landward
of
the
coast
line.
Thus,
only
a
small
fraction
of
SPCC­
regulated
facilities
are
affected
by
the
EO
and
MOU,
and
the
majority
of
those
facilities
were
already
taken
into
account
in
the
benefits
analysis.

Permanently
closed
containers.
We
believe
that
containers
that
have
been
permanently
closed
according
to
the
standards
prescribed
in
the
rule
qualify
for
the
designation
of
"permanently
closed,"
whether
they
have
been
closed
before
or
after
the
effective
date
of
the
rule.
Containers
that
cannot
meet
the
standards
prescribed
in
the
rule
will
not
qualify
as
permanently
closed.
To
clarify
when
a
container
has
been
closed,
we
have
amended
the
rule
to
require
that
the
sign
noting
closure
show
the
date
of
such
closure.
The
date
of
such
closure
must
be
noted
whether
it
occurred
before
or
after
the
effective
date
of
this
provision.
Some
States
and
localities
require
a
permit
for
tank
closure.
A
document
noting
a
State
closure
inspection
may
serve
as
evidence
of
container
closure
if
it
is
dated.

Recordkeeping
requirements.
We
agree
that
a
requirement
to
retain
records
for
five
years
is
too
long,
and
have
withdrawn
the
proposed
requirement
in
favor
of
the
general
requirement
in
§112.7(
e)
to
maintain
records
for
three
years.

Secondary
containment.
We
appreciate
the
comments
providing
associated
cost
of
compliance
data.
We
note
that
we
have
improved
the
methodology
used
to
estimate
the
effects
of
the
rule
by
expanding
the
types
of
model
facilities
used
in
the
analysis.
The
costs
we
have
estimated
for
each
model
facility
type
are
approximations
that
are
meant
to
reflect
average
costs
to
a
facility
having
similar
characteristics
as
our
model
facility.
In
reality
some
facilities
will
experience
higher
or
lower
costs
than
what
we
have
estimated.
Overall,
however,
we
believe
that
this
technique
gives
us
a
reasonable
estimate
of
the
program's
entire
costs
and
cost
savings.

Scientific
rationale.
We
believe
that
each
of
the
revisions
to
the
SPCC
rule
being
adopted
have
an
adequate
scientific,
policy,
and
legal
basis.
In
response
to
comment,
we
have
not
promulgated
a
number
of
proposed
provisions.
320
State
and
local
regulation.
We
disagree
that
the
rule
is
unnecessary
because
State
and
local
agencies
already
regulate
aboveground
storage
tanks.
Both
the
States
and
EPA
have
authority
to
regulate
containers
storing
or
using
oil.
We
believe
State
authority
to
regulate
in
this
area
and
establish
spill
prevention
programs
is
supported
by
section
311(
o)
of
the
CWA.
Some
States
have
exercised
their
authority
to
regulate
while
others
have
not.
We
believe
that
State
SPCC
programs
are
a
valuable
supplement
to
our
SPCC
program.
We
do
not
preempt
State
rules,
and
defer
to
State
law
that
is
more
stringent
than
part
112.

We
also
note
that
you
may
now
use
a
State
plan
as
a
substitute
for
an
SPCC
Plan
when
the
State
plan
meets
all
Federal
requirements
and
is
cross­
referenced.
When
you
use
a
State
plan
that
does
not
meet
all
Federal
requirements,
it
must
be
supplemented
by
sections
that
do
meet
all
Federal
requirements.
At
times
EPA
will
have
rules
that
are
more
stringent
than
States
rules,
and
some
States
may
have
rules
that
are
more
stringent
than
those
of
EPA.
If
you
follow
more
stringent
State
rules
in
your
Plan,
you
must
explain
that
is
what
you
are
doing.

Triennial
review.
We
have
extended
the
time
in
which
an
owner
or
operator
must
review
the
Plan
from
at
least
once
every
three
years
to
at
least
once
every
five
years.
As
a
result,
we
expect
that
facility
owners
or
operators
will
experience
an
overall
reduction
in
the
annualized
cost
of
conducting
such
a
review.
The
costs
associated
with
this
activity
are
baseline
costs
that
we
have
already
determined
in
numerous
information
collection
burdens.
The
impacts
of
this
change
are
discussed
in
the
supporting
analyses
to
the
rule.
Further,
we
have
clarified
in
the
final
rule
that
a
PE
must
certify
only
technical
Plan
amendments.

XVI
­
H:
Miscalculation
of
benefits
Comments:
Costs,
benefits.
The
benefit
values
calculated
in
the
analyses
are
too
great,
and
the
economic
benefit
of
applying
the
proposed
changes
to
oil
and
gas
production
facilities
is
far
outweighed
by
the
cost.
The
benefits
of
the
proposed
changes
would
be
at
most
in
the
tens
of
thousands
of
dollars
per
year.
(28,
165)
We
failed
to
accurately
predict
the
costs,
and
we
overestimated
the
benefits
of
the
proposed
regulation
in
spite
of
the
economic
analyses.
(35)
We
quantified
the
benefits
in
incredibly
broad
terms,
and
we
counted
spill
reductions
as
benefits,
even
though
we
already
counted
these
as
benefits
of
prior
regulations.
(128)

Discharges
avoided.
Disagrees
with
our
estimate
found
in
the
Supplemental
Cost
and
Benefit
Analysis
for
the
benefits
associated
with
avoiding
cleaning
up
an
oil
spill.
The
cost
to
clean
up
such
a
spill
is
considerably
less,
and
therefore
our
benefit
estimation
is
too
high.
(101)
Although
we
cite
as
a
potential
benefit
the
increased
revenue
from
sales
of
petroleum
products
not
lost
in
spills,
a
facility
owner
or
operator
already
strives
to
avoid
spill
events
wherever
possible
due
to
the
stated
incentive.
(L27)
321
Facility
notification.
We
have
not
described
how
we
monetized
the
benefits
of
the
proposed
notification
form
and
regulatory
revisions.
However,
we
cannot
possibly
monetize
these
benefits
without
first
identifying
any
problems
with
the
current
SPCC
program.
(31,
34)
We
should
not
count
as
a
benefit
compliance
with
the
proposed
notification
provision,
and
noted
that
this
action
is
actually
a
burden.
(128)

Human
health
and
the
environment.
The
benefits
resulting
from
the
proposed
regulations
will
have
little
if
any
benefit
in
protecting
human
health
or
the
environment
and
do
not
justify
the
standards
we
are
requiring
for
facilities
subject
to
the
part
112
requirements.
(28,
74,
110,
113,
137,
149,
160,
192)

Response:
Costs,
benefits.
We
disagree
that
we
failed
to
accurately
predict
the
costs,
and
that
we
overestimated
the
benefits
of
the
rule
in
spite
of
the
economic
analyses.
We
believe
that
we
have
adequately
explained
in
our
economic
analysis
the
methods
used
to
predict
costs
and
benefits.
The
final
rule
will
reduce
costs
by
millions
of
dollars
a
year
for
regulated
facilities.

Discharges
avoided.
Our
method
of
calculating
benefits
for
the
1991
proposal
involved
an
attempt
to
quantify
the
value
of
avoided
oil
spilled
and
associated
clean­
up
costs
that
would
result
from
the
proposal.
While
some
commenters
believe
that
we
may
have
overestimated
the
unit
cost
of
clean­
up
for
some
types
of
facilities,
we
believe
that
our
overall
estimate
was
fairly
reliable
because
we
most
likely
underestimated
clean­
up
unit
costs
for
other
types
of
facilities.
As
we
noted
in
the
analysis,
"the
cost
to
clean
up
oil
spills
may
vary
substantially,
depending
on
a
number
of
parameters
including:
the
environmental
medium
that
is
contaminated;
the
sensitivity
of
the
environment
to
spills
(spills
to
wetlands);
the
size
of
the
spill;
the
type
of
oil;
and
the
length
of
time
it
takes
for
a
response
action
to
begin,
among
others."
Since
we
initially
performed
this
analysis,
there
has
been
substantial
development
in
this
area
as
a
result
of
the
Oil
Pollution
Act
of
1990
(OPA).

Facility
notification.
We
have
withdrawn
the
facility
notification
proposal.
Therefore,
there
are
no
costs
associated
with
it
in
the
final
rule.

Human
health
and
the
environment.
We
disagree
that
the
rule
will
have
little
if
any
benefit
in
protecting
human
health
or
the
environment
and
does
not
justify
the
standards
we
are
requiring
for
facilities
subject
to
the
part
112
requirements.
We
believe
that
the
final
rule
will
reduce
the
overall
compliance
costs
to
industry
without
sacrificing
any
protection
to
the
environment.
As
previously
noted,
the
measurable
benefits
attributable
to
the
final
rule
are
related
to
the
estimated
reduction
in
associated
burden
for
SPCCregulated
facilities.
We
believe
this
burden
reduction
will
be
approximately
40
percent
for
the
regulated
universe.
This
reduction
is
principally
associated
with
our
decision
to
incorporate
many
industry
standards
and
practices
into
the
rule,
along
with
the
decision
to
extend
the
length
of
time
in
which
a
facility
owner
or
operator
must
review
and
evaluate
the
Plan.
We
also
have
adopted
a
number
of
revisions
designed
to
increase
the
flexibility
a
facility
needs
to
comply
with
the
requirements
of
the
rule.
We
have
not
adopted
the
notification
provision
and
the
72­
hour
impermeability
standard
for
secondary
containment,
322
which
many
commenters
opposed
based
on
associated
costs.
Further,
we
have
decided
to
no
longer
regulate
small
facilities
storing
less
than
1,
320
gallons
in
a
single
aboveground
container.

We
note
that
while
we
did
not
describe
how
we
monetized
the
estimated
benefits
of
the
proposed
rulemaking
in
the
preamble,
we
did
provide
a
cite
to
the
Supplemental
Cost
and
Benefit
Analysis
of
the
Proposed
Revisions,
which
was
available
to
the
public
throughout
the
rulemaking
process.
323
Category
XVII:
General
comments
XVII­
1
Support
or
opposition
to
the
proposed
rule
Comments:
Support
for
proposed
rule.
The
proposed
revisions
clarify
and
strengthen
the
SPCC
program
and
protect
the
navigable
waters
of
the
United
States.
(4,
27,
54,
64,
67,
81,
82,
105,
107,
115,
135,
136,
142,
147,
153,
158,
161,
164,
181,
184)
The
proposed
amendments
would
"enhance
the
safety
of
the
SPCC
program."
(54)
The
revisions
would
make
the
regulation
clearer
and
facilitate
compliance.
(136)
The
revisions
would
make
the
SPCC
program
enforceable.
(184)
The
proposed
changes
would
help
prevent
major
problems
with
aboveground
storage
tanks
and
piping
systems.
(L1)
There
would
be
"no
dual
regulation
in
offshore
areas."
(L12)

Opposition
to
proposed
rule.

Burdensome
or
costly.
Implementing
the
proposed
rule
would
be
burdensome.
(83,
91,
102)
The
proposed
requirements
would
force
the
regulated
community
to
ignore
the
rule,
or
go
out
of
business.
(122)
The
proposed
requirements
would
impose
expensive
and
unnecessary
administrative
burdens,
monitoring
and
reporting
requirements,
and
other
excessive
compliance
costs
on
a
facility.
(35,
86,
111,
113,
131,
184,
189,
192,
L35)
We
must
consider
drafting
regulations
that
protect
the
environment,
and
are
affordable
to
this
country's
businesses.
(139)

Current
rule
adequate.
Current
SPCC
regulations
are
adequate
to
assure
the
protection
mandated
by
the
CWA
and
the
Oil
Pollution
Act
(OPA).
(35,
71,
101,
192,
L30)
Existing
regulations
are
adequate,
and
further
regulatory
measures
are
not
necessary.
(110,
149)

Decreased
flexibility.
Adopting
the
proposed
requirements
would
limit
or
curtail
the
flexibility
in
the
current
regulation.
(35,
91,
L30)
Adopting
our
proposals
would
not
benefit
the
environment.
(35,
86,
148,
L35)
The
proposed
rule
is
"highly
inflexible."
(184)

Interpretation.
The
proposed
revisions
have
been
"subject
to
incorrect
and
unnecessary
interpretation."
(100,
103)

OPA.
We
should
not
promulgate
the
proposed
revisions.
(101)
The
proposed
rulemaking
did
not
implement
the
Oil
Pollution
Act
of
1990
(OPA).
(31,
34,
35)

Production
facilities.
Oil
and
gas
exploration
and
production
and
gas
processing
industries
have
been
"highly
effective
in
implementing
the
SPCC
program
and
in
controlling
releases
of
oils
to
the
waters
of
the
United
States."
Our
"substantial"
proposed
revisions
were
unjustified
given
the
record
of
losses
in
the
production
sector,
and
the
relatively
small
size
and
isolated
location
of
most
production
facilities.
(86)
324
Reduced
environmental
protection.
In
some
cases,
the
proposed
rule
could
"decrease
the
protection
afforded
under
the
current
rule."
Many
operators
prepare
SPCC
Plans
for
all
storage
facilities
­­
regardless
of
how
close
the
facility
is
to
navigable
waters.
Overly
burdensome
SPCC
Plan
requirements
such
as
we
proposed,
could
discourage
owners
or
operators
from
continuing
that
practice.
(86)

Substantial
risk.
Supports
the
proposed
rule
only
insofar
as
it
addresses
the
standards
applicable
to
facilities
that
pose
a
substantial
risk
to
navigable
waters
of
the
U.
S.
because
they
store
or
handle
large
bulk
quantities
of
oil.
(156)

Technically
ill­
conceived.
The
proposed
regulation
is
technically
ill­
conceived.
(110)

Unnecessary.
The
proposed
regulations
are
unnecessary.
(35,
71,
113)
The
proposed
requirements
would
result
in
a
considerable
burden
and
expense
for
facilities,
with
no
commensurate
environmental
benefit.
(88,
153,
167)
The
proposed
changes
would
not
improve
the
overall
effectiveness
of
oil
pollution
program
regulations.
(103)

Vague.
Certain
proposed
provisions
are
unclear
and
technically
impractical.
(67,
83,
91,
100,
102,
103,
131)

Response:
Support
for
proposed
rule.
We
appreciate
commenter
support.

Opposition
to
proposed
rule.
We
disagree
with
the
general
opposition
to
the
proposed
changes.
We
proposed
the
changes
largely
to
make
part
112
clearer
and
simpler,
to
reflect
expanded
jurisdiction
under
the
CWA,
and
to
respond
to
recommendations
of
the
SPCC
Task
Force
and
General
Accounting
Office
report.
We
have
considered
comments
on
the
technical
viability
of
the
proposed
requirements
and
made
many
changes
in
the
rule
based
on
those
comments.

Further,
the
final
rule
contains
a
number
of
provisions
designed
to
decrease
regulatory
burdens
on
an
owner
or
operator.
It
gives
him
greater
flexibility
than
the
current
rule
by
allowing
him
to
choose
methods
that
best
protect
the
environment.
We
maintain
the
good
engineering
practice
standard
which
encourages
an
owner
or
operator
to
use
industry
consensus
or
other
appropriate
standards,
rather
than
prescribing
particular
procedures,
or
monitoring
or
inspection
schedules.
For
most
of
the
substantive
requirements,
when
a
facility
owner
or
operator
can
demonstrate
that
a
particular
provision
is
infeasible
based
on
facility­
specific
circumstances,
an
owner
or
operator
may
substitute
alternative
measures
that
provide
environmental
protection
equivalent
to
part
112
requirements.

In
1991,
we
prepared
two
preliminary
economic
analyses
to
support
the
proposed
rule,
including
an
initial
economic
impact
analysis
under
Executive
Order
(EO)
12291
and
a
supplemental
cost
and
benefit
analysis.
For
the
final
rule,
we
have
assessed
the
economic
effects
as
required
by
EO
12866
and
relevant
statutes.
We
think
that
we
have
325
considered
costs
and
burdens
adequately,
and
invite
the
interested
reader
to
review
the
Regulatory
Analyses
at
the
end
of
the
preamble
to
the
rule
we
adopted
and
the
docket
for
this
rulemaking.

XVII­
2
Editorial
changes
and
clarifications
Comments:
ANPRM.
Asks
us
to
use
an
Advance
Notice
of
Proposed
Rulemaking
(ANPRM)
for
discussing
issues
on
which
we
simply
asked
for
comments.
(121)

Plain
language,
"countermeasure."
We
should
use
the
active
voice
and
simple
English.
Part
112
is
unnecessarily
wordy.
(121)
We
should
drop
the
"s"
from
countermeasures
in
the
proposed
rule.
(7,
9,
121)
We
should
make
the
same
change
in
40
CFR
part
264.
(7)

Recommendations.
Asks
us
to
simplify
the
regulation
by
omitting
recommendations
or
discretionary
provisions.
Suggests
that
we
develop
a
separate
"Code
of
Good
Practice"
for
recommendations.
We
would
have
difficulty
enforcing
provisions
where
we
did
not
use
an
imperative
statement.
(44,
121)

Syntax
and
grammar.
Several
commenters
made
suggestions
regarding
syntax
and
grammar.
(27,
54,
76,
79,
100,
121,
L26)
.

Response:
ANPRM.
We
believe
that
it
would
have
been
redundant
to
use
an
Advance
Notice
of
Proposed
Rulemaking
(ANPRM)
for
discussing
issues
on
which
we
simply
asked
for
comments
in
1991.
The
1991
preamble
was
an
appropriate
mechanism
for
the
comment
request.

Plain
language,
"countermeasure."
We
have
made
changes
to
correct
grammar
and
typographical
errors,
to
promote
consistency,
and
used
a
plain­
English
format
to
make
part
112
clearer
and
easier
to
use.
A
plain
English
format
includes
maximum
use
of
the
active
voice;
short,
clear
sentences;
and,
in
this
rule,
a
summary
of
the
major
regulatory
changes.
Using
this
format
is
part
of
our
continuing
regulatory
reinvention
efforts.
We
have
revised
the
term
"countermeasures"
to
read
"countermeasure"
in
the
term
Spill
Prevention,
Control,
and
Countermeasure
Plan.
We
cannot
revise
"countermeasures"
in
40
CFR
part
264
as
part
of
this
rulemaking
because
we
did
not
propose
any
changes
to
that
part.

Recommendations.
We
have
not
included
discretionary
provisions
in
the
final
rule
because
we
do
not
wish
to
confuse
the
regulated
community
by
being
unclear
about
what
is
mandatory
and
what
is
discretionary.
We
will
provide
guidance
or
policy
statements,
as
necessary,
that
will
include
some
or
all
of
these
recommendations.
In
the
absence
of
such
guidance
or
policy
statements,
we
urge
an
owner
or
operator
to
look
to
current
industry
standards
for
guidance
on
technical
issues.

Syntax
and
grammar.
We
have
corrected
errors
in
syntax
and
grammar.
326
XVII­
3
Public
participation
and
call
for
more
data
Comments:
Basis
for
rule.
We
did
not
discuss
what
major
release
or
spill
scenarios
compelled
us
to
propose
changes,
nor
why
the
proposed
changes
would
improve
the
situation.
We
should
show
more
data
and
empirical
evidence
that
demonstrate
why
the
regulation
is
necessary.
We
should
re­
propose
this
rule
based
on
new
data,
which
display
and
target
the
design
and
operating
problems
that
require
improvement.
(148)
Our
data
is
deficient
because
we
did
not
use
Petroleum
Extraction
Industry
statistical
data
or
State
data.
(L27)

Liner
Study.
Section
4113
of
OPA
required
the
President
"to
conduct
a
liner
study,
report
the
study
results
to
Congress,
and
implement
the
study
recommendations
six
months
after
the
report.
We
have
not
completed
the
study
and
have
not
made
it
available
to
commenters.
We
should
withdraw
proposed
regulations
on
secondary
containment
until
we
complete
the
study,
and
the
affected
industry
had
an
opportunity
to
comment
on
the
study
during
rulemaking.
(32)
We
should
release
this
study
for
public
comment
before
submitting
it
to
Congress
so
that
we
have
the
full
benefit
of
industry's
practical
experiences
with
liners
and
other
means
of
containment.
(54)

SPCC
Task
Force.
We
left
out
many
small
businesses
in
America
by
consulting
only
with
American
Petroleum
Institute
(API),
and
not
with
the
Oklahoma
Independent
Petroleum
Association
(OIPA)
or
the
Independent
Petroleum
Association
of
America
(IPAA).
(11)
We
should
have
included
Professional
Engineers
on
the
SPCC
Task
Force
(Task
Force).
(11,110)
Criticizes
the
Task
Force
because
it
was
composed
entirely
of
Federal
and
State
regulatory
officials
and
notes
that
there
were
no
representatives
from
affected
industries
or
State
oil
and
gas
commissions.
The
Task
Force
could
not
have
evaluated
regulatory
issues
impartially,
or
have
received
sufficient
input
regarding
potential
regulatory
impacts
on
industry.
The
Task
Force
report
was
of
extremely
limited
value
as
a
basis
for
rulemaking.
(32)

Response:
Basis
for
rule.
We
disagree
that
we
did
not
state
our
purpose
in
the
proposed
rule,
and
refer
the
reader
to
our
extensive
discussion
of
the
proposals
in
the
NPRM.
Similarly,
we
cannot
agree
that
our
data
and
analyses
are
deficient,
and
refer
the
reader
to
the
rulemaking
docket
for
our
supporting
data
and
analyses.
We
note
that
we
receive
additional
data
from
industry
representatives
and
other
interested
persons
which
we
considered
throughout
our
rulemaking
process.

Liner
Study.
We
completed
the
liner
study
and
published
a
report
to
Congress
in
May
1996.
The
study
is
available
to
interested
readers
on
our
website
at
epa.
gov/
oilspill.

SPCC
Task
Force.
Federal
regulatory
agencies
must
observe
various
procedural
requirements
to
assure
that
there
is
adequate
opportunity
for
the
public
to
participate
in
rulemakings.
While
the
membership
of
the
task
force
may
not
have
included
certain
groups,
everyone
had
the
opportunity
to
comment
on
the
proposal.
We
considered
all
comments
and
made
many
changes
based
on
them.
327
XVII­
4
Adequacy
of
existing
Plans
Background:
In
1991,
we
requested
comments
on
whether
existing
SPCC
Plans
were
adequate
to
meet
the
requirements
of
the
regulation
we
proposed.
We
requested
comments
to
help
us
estimate
the
extent
to
which
the
proposed
requirements
may
impose
new
compliance
costs.

Comments:
Existing
SPCC
Plans
would
not
meet
the
provisions
we
proposed.
(16,
36,
79,
L8,
129)
Owners
or
operators
would
have
to
modify
existing
Plans
if
we
adopt
the
new
provisions
included
in
the
proposed
regulation.
(16,
79,
L8)

Response:
Many
Plans
will
only
need
to
include
cross­
referencing
modifications.
An
owner
or
operator
will
find
it
necessary
to
modify
his
existing
Plan
to
meet
the
requirements
of
the
final
rule,
if
only
to
cross­
reference
existing
requirements
to
redesignated
requirements.
To
reduce
the
burden,
we
permit
the
use
of
a
Plan
supplement
which
cross­
references
the
location
of
requirements
listed
in
the
revised
rule
with
the
equivalent
requirements
in
an
existing
Plan.
In
the
final
rule
preamble,
we
provide
a
table
to
assist
owners
or
operators
with
this
cross­
referencing.

XVII­
5
Other
comments
Comments:
Comments.
We
should
consider
all
comments
on
the
proposed
regulations,
including
those
from
the
regulated
community.
(135)

Comprehensive
program.
The
proposed
regulation
will
be
ineffective
in
preventing
spills,
unless
we
substantially
increase
staff
for
facility
inspections
and
enforcement.
Using
part
112
in
1991
would
have
lessened
the
justification
for
a
new
up­
to­
date
and
comprehensive
national
aboveground
tank
law.
We
should
work
with
Congress
to
develop
a
comprehensive
spill
prevention
program,
rather
than
follow
a
piecemeal
approach
to
oil
spill
prevention.
(111)

Drafting.
When
we
draft
regulations,
we
should
acknowledge
company
efforts.
(139)
In
promulgating
the
final
rule,
we
should
eliminate
"broadly
written
statements
that
would
expand
the
coverage
of
this
proposal
without
increasing
the
environmental
benefit."
(L6)

Generic
Plans.
We
were
incorrect
in
assuming
that
a
widespread
practice
for
owners
or
operators
of
large
companies
is
to
develop
generic
SPCC
Plans
without
considering
specific
plant
requirements.
(39)

Reducing
pollution.
We
should
provide
incentives
for
reducing
the
potential
for
oil
pollution
of
navigable
waters.
(L12)

Substantive
changes.
The
proposed
regulations
represent
"substantial
requirements
and
not
mere
clarifications."
Cites
substantive
requirements
and
"should
to
shall"
changes
as
examples.
By
failing
to
give
fair
notice
of
the
nature
of
our
proposed
revisions
to
the
Oil
328
Pollution
Prevention
regulations,
we
did
not
provide
for
adequate
public
participation
in
the
rulemaking
process,
as
we
are
required
to
do
under
553(
b)
of
the
APA.
(32)

Response:
Comments.
We
have
carefully
considered
all
comments,
and
made
many
changes
based
on
them.
The
final
rule
protects
the
environment
while
reducing
the
information
collection
burden
on
the
regulated
community.

Comprehensive
program.
We
appreciate
the
commenter's
concern
regarding
our
program
funding.
We
agree
that
a
comprehensive
approach
to
oil
pollution
prevention
is
best.
To
further
that
approach,
the
SPCC
program
and
the
UST
program
have
worked
together
to
eliminate
duplicative
regulation
in
this
rule.
Except
for
facility
diagram
requirements,
we
have
eliminated
from
the
SPCC
program
all
completely
buried
tanks
subject
to
all
of
the
technical
regulations
of
40
CFR
part
280
or
of
a
State
program
approved
under
40
CFR
part
281.

Drafting.
We
agree
that
we
should
eliminate
"broadly
written
statements
that
would
expand
the
coverage
of
this
proposal
without
increasing
the
environmental
benefit,"
and
believe
we
have
done
so.
We
also
acknowledge
company
efforts
to
protect
the
environment
and
to
comply
with
the
rule.

Generic
Plans.
We
do
not
assume
and
never
have
assumed
that
it
is
a
widespread
practice
for
owners
or
operators
of
large
companies
to
develop
generic
SPCC
Plans
without
considering
specific
plant
requirements.
We
do
acknowledge
that
most
companies
attempt
to
comply
with
the
rule.
In
response
to
the
comment
that
we
should
provide
incentives
for
reducing
the
potential
for
oil
pollution
of
navigable
waters,
we
agree
and
have
done
so.
We
have
retained
the
flexibility
in
the
rule
that
permits
an
owner
or
operator
to
use
alternate
methods
to
achieve
pollution
prevention
goals.

Reducing
pollution.
We
agree
that
we
should
provide
incentives
for
reducing
the
potential
for
oil
pollution
of
navigable
waters
and
believe
we
have
done
so
in
this
rule.
Incentives
include
flexible
formatting
and
recordkeeping,
use
of
industry
standards,
and
the
availability
of
deviations
for
most
substantive
provisions.

Substantive
changes.
We
disagree
that
"the
should
to
shall
to
must"
change
is
substantive.
See
the
discussion
in
section
IV.
C.
in
the
preamble
to
today's
final
rule.
The
changes
to
the
text
of
existing
substantive
requirements
are
mostly
clarifications.
There
are
few
new
requirements
in
the
final
rule.
Moreover,
we
discussed
the
"should"
to
"shall"
issue
in
the
preamble
of
the
proposed
rule.

XVII­
6
Request
to
extend
the
comment
period
and
hold
public
hearings
Background:
In
1991,
we
said
that
we
would
consider
comments
submitted
on
or
before
December
23,
1991,
which
was
60
days
after
we
published
the
proposed
rule.
We
also
said
that
if
the
comments
we
received
indicated
sufficient
need,
we
would
consider
holding
a
public
hearing
329
Comments:
Extension
of
comment
period.
Many
commenters
asked
for
30
to
60
more
days
to
comment.
(13,
17,
18,
19,
20,
31,
42,
58,
108,
110,
120,
122,
142,
160,
184,
L22).
Requests
more
time,
asserting
that
the
rule
was
lengthy
and
complicated.
(13,
20)
Requests
more
time
to
review
the
economic,
fire
safety,
and
environmental
consequences
of
our
proposed
changes.
(17)
End­
of­
the­
fiscal­
year
requirements
prevented
reviewing
the
proposed
rule
in
the
60­
day
time
frame.
(18,
19,
20)
Although
we
allowed
commenters
60
days
to
respond
to
our
proposed
changes,
commenters
had
only
45
days
by
the
time
a
copy
of
the
Federal
Register
arrived
in
the
mail.
The
commenters
also
noted
that
they
had
to
wait
to
receive
copies
of
the
economic
analyses
that
we
made
available
through
the
mail
upon
request.
(31,
110)
Requests
an
extension
to
review
the
equipment
upgrade
and
soil
removal
requirements.
(160)
Asks
for
an
extension
for
time
to
visit
and
learn
more
about
facilities
affected
by
the
proposed
changes.
(184)
A
State
rule
revision
process
is
insufficiently
advanced
to
allow
commenters
to
provide
comments
within
our
time
frame.
(L22)

Public
hearings.
We
should
hold
public
hearings
to
discuss
the
proposed
changes.
(11,
31,
35,
42,
79,
110,
129,
142,
L28)
Public
hearings
would
benefit
small
businesses
without
staff
to
monitor
the
Federal
Register.
(11)
Asks
that
we
hold
public
hearings
in
locations
throughout
the
United
States
for
small
businesses
without
the
money
to
travel
to
Washington,
D.
C.
(11,
31,
L28)
Holding
public
hearings
would
give
the
regulated
community
a
chance
to
present
an
accurate
assessment
of
the
costs
associated
with
the
proposed
changes.
(31)
Asks
us
to
grant
an
extension
and
hold
public
hearings
to
give
petroleum
exploration
and
production
facility
owners
or
operators
an
opportunity
to
inform
us
about
the
broad
impacts
of
the
proposed
rule
on
these
facilities.
(142)

Response:
Extension
of
comment
period.
While
we
did
not
extend
the
comment
period
for
the
1991
rulemaking,
we
believe
that
a
60­
day
comment
period
was
adequate,
and
consistent
with
other
Federal
agencies.
We
note
that
we
considered
comments
received
as
late
as
April
1993.

Public
hearings.
We
decided
that
there
was
insufficient
need
for
a
public
hearing
because
the
written
comments
provided
exhaustive
arguments
on
each
side
of
nearly
every
relevant
issue.

XVII­
7
Support
for
comments
submitted
by
other
commenters
Background:
We
received
many
comments
from
writers
who
simply
endorsed
a
letter
or
position
of
another
writer.

Comments:
Support
for
the
Utility
Solid
Waste
Activities
Group
comments
on
part
112.
(92,
100,
130,
138,
163,164)
Support
for
Utility
Water
Act
Group
comments.
(100,
120,
130,
138,
163)
Support
for
Ohio
Electric
Utilities
Institute
comments.
(163)
Support
for
comments
from
the
Edison
Electric
Institute,
the
American
Public
Power
Association,
and
the
National
Rural
Electric
Cooperative
Association.
(138)
330
Support
for
comments
from
the
American
Petroleum
Institute.
(64,
83,
85,
91,
94,
96,
97,
102,
133,
173,
174)
Support
for
the
Rocky
Mountain
Oil
and
Gas
Association
comments.
(174)

Support
for
comments
from
the
Independent
Petroleum
Association
of
America.
(160,
167)
Support
for
comments
from
the
Mitchell
Energy
and
Development
Corporation
and
the
American
Exploration
Company.
(160)
Support
for
comments
from
the
Institute
of
Shortening
and
Edible
Oils,
Inc.
(30),
and
the
Ohio
Oil
and
Gas
Association
(59).

Response:
For
responses
to
specific
comments,
refer
to
the
appropriate
sections
of
this
document.
