containers, the rule does not establish a required frequency and the
owner or

operator of the facility or PE can establish an inspection schedule to
account for the chemical and physical characteristics of the oil being
stored and for any other factors which may affect the integrity of a
bulk storage container. In response to the comment requesting that EPA
allow visual inspection and secondary containment instead of integrity
testing on AFVO storage containers, EPA notes that the revisions to
Sec.  112.12(c)(6) may allow the owner or operator to conduct visual
inspections to satisfy the integrity testing requirements, as long as
they are conducted in accordance with industry standards.
    EPA is also finalizing changes to Sec.  112.12(c)(6) incorporating
industry standards into an integrity testing program for AFVO bulk
storage containers (consistent with the provision finalized at Sec.
112.8(c)(6) for other oils). EPA also believes there is sufficient
flexibility provided in Sec.  112.7(a)(2) to make an environmental
equivalence determination with respect to developing a hybrid integrity
testing program. Therefore, EPA believes that the rule already allows
other design approaches, other industry standards, or other good
engineering practices to be used alone or as a 'hybrid' program where
equivalent results in meeting the SPCC requirements are obtained.
    Regarding the comments suggesting that integrity testing should
follow specific fiberglass tank and pipe industry standards (FTPI 2007-
1), the SPCC rule requires that the Plan be prepared in accordance with
good engineering practices, including consideration of applicable
industry standards (Sec.  112.3(d)(1)(iii)). An owner or operator may
follow the fiberglass tank and pipe standards, if appropriate for the
particular facility's characteristics. Thus, the rule already provides
for this. However, it should be noted that when a standard (or any part
of a standard) is incorporated into a facility's SPCC Plan, then
adherence to that standard (or part of a standard) is mandatory for
implementation of the Plan.
    In response to the proposed differentiated integrity testing
requirements for certain AFVO bulk storage containers, several
commenters requested an exemption for bulk storage containers holding
milk. The Agency considered comments supporting an exemption of certain
milk bulk storage containers from the SPCC requirements. PMO is a model
ordinance maintained through a cooperative agreement between the
states, the FDA, and the regulated community. States typically adopt it
either by reference or by directly incorporating its requirements into
statutes or regulations. EPA agrees with commenters that milk
containers merit further consideration with respect to SPCC rule
applicability and the PMO. Thus, in the near future, EPA intends to
publish a proposed rule on alternative regulatory approaches for milk,
including an exemption based upon the PMO.

M. Oil Production Facilities

    Since its original promulgation in 1973, the SPCC rule has included
differentiated requirements for oil production facilities (Sec.
112.9), as compared to other types of facilities (Sec. Sec.  112.8,
112.10, 112.11, and 112.12). Based on issues presented by the regulated
community, EPA is finalizing certain revisions that further streamline,
tailor or clarify the SPCC requirements for oil production facilities.
Specifically, EPA is finalizing the following modifications for oil
production facilities: excluding oil production facilities from the
loading/unloading rack requirements at Sec.  112.7(h), as described in
Section V.F of this action; revising the definition of ``production
facility''; extending the timeframe by which the owner or operator of a
new oil production facility must prepare and implement an SPCC Plan;
providing an alternative option for flow-through process vessels at oil
production facilities to comply with the general secondary containment
requirement and additional oil spill prevention measures in lieu of
sized secondary containment requirements; providing an exemption for
certain intra-facility gathering lines from the SPCC requirements;
providing an alternative option for flowlines and intra-facility
gathering lines at oil production facilities for contingency planning
in lieu of all secondary containment requirements, while establishing
more prescriptive requirements for a flowline/intra-facility gathering
line maintenance program; providing compliance alternatives for certain
produced water containers that do not contain oil as certified by a PE;
providing compliance alternatives to sized secondary containment for
produced water storage containers that are not otherwise exempt;
establishing alternative criteria for an oil production facility to be
eligible to self-certify an SPCC Plan as a qualified facility; and
clarifying the definition of ``permanently closed'' as it applies to an
oil production facility.
1. Definition of Production Facility
    As described in Section V.D of this action, EPA is modifying the
definition of ``facility'' to clarify that contiguous or non-contiguous
buildings, properties, parcels, leases, structures, installations,
pipes, or pipelines may be considered separate facilities, and to
specify that the ``facility'' definition governs the applicability of
40 CFR part 112. To provide clarity consistent with these revisions,
EPA is also finalizing modifications to the definition of ``production
facility.'' A ``production facility'' is a type of ``facility'' as
defined in Sec.  112.2. The revised definition reads as follows:
``Production facility means all structures (including but not limited
to wells, platforms, or storage facilities), piping (including but not
limited to flowlines or intra-facility gathering lines), or equipment
(including but not limited to workover equipment, separation equipment,
or auxiliary non-transportation-related equipment) used in the
production, extraction, recovery, lifting, stabilization, separation or
treating of oil (including condensate) and associated storage or
measurement and is located in an oil or gas field, at a facility. This
definition governs whether such structures, piping, or equipment are
subject to a specific section of this part.''
    With these revisions, EPA is adding a sentence at the end of the
definition to clarify that while only the definition of ``facility''
governs the overall applicability of 40 CFR part 112, the definition of
``production facility'' is used to determine which sections of the rule
may apply at a particular facility. (The sections for administrative
and general rule requirements continue to apply to all facilities under
40 CFR part 112.) This change to the definition of production facility
addresses concerns raised during litigation challenging the 2002 rule
amendments and discussed in the May 25, 2004 Federal Register notice
(69 FR 29728). EPA has also modified the phrase ``and located in a
single geographical oil or gas field operated by a single operator'' to
clarify that a production facility ``is located in an oil or gas
field.'' This is consistent with this rulemaking's revisions to the
definition of ``facility'' that emphasize the flexibility in how a
facility owner or operator can determine the boundaries of a facility.
a. Comments
    Several commenters expressed general support for EPA's proposed
amendments to the definition of ``production facility.'' However, one
commenter stated that the reference to `* * * property, parcels, leases
* * *' in the definition of ``facility'' causes uncertainty because
leases regularly extend beyond the size of a production facility.
Several commenters also

suggested that the proposed addition of the phrase ``may be,'' would
cause the definition to become ambiguous.
    The Agency also received comment on various other suggested
options. For example, operators of facilities producing AFVO requested
that EPA clarify that this section applies only to petroleum oil
production by adding the word ``petroleum'' to the definition of
production facility, while several other commenters suggested removing
the reference to ``a single geographical oil or gas field'' to reduce
confusion. Several commenters expressed concerns regarding multi-
facility Plans for production facility operations. Another commenter
requested EPA remove the phrase ``gathering line'' from the definition
of production facility to avoid dual jurisdiction. Two commenters
requested additional clarity regarding natural gas and the definition
of production facility. Finally, two commenters suggested that EPA
include additional infrastructure, activities and equipment that
support production operations under the specific requirements of Sec.
112.9, or requested use of a ``primary function'' test of a facility to
determine the facility's applicability to specific sections of the SPCC
regulation.
b. Response to Comments
    EPA agrees with those commenters who supported the modifications to
the definition, and is finalizing revisions to the definition of
``production facility,'' with certain changes as described in this
section. The Agency disagrees that the revised definition leads to
industry uncertainty. The changes clearly indicate that the definition
of production facility specifically identifies which rule requirements
apply to a facility. For example, oil production facilities are
excluded from the rule requirements in Sec.  112.8: ``Spill Prevention,
Control, and Countermeasure Plan requirements for onshore facilities
(excluding production facilities),'' whereas the rule requirements in
Sec.  112.9: ``Spill Prevention, Control, and Countermeasure Plan
requirements for onshore oil production facilities'' specify that these
requirements only apply to production facilities.
    EPA also disagrees with the commenter who suggested that the
addition of the term ``petroleum'' to the definition of production
facility is necessary. The addition of the term ``petroleum'' is
unnecessary because the definition itself indicates that the type of
facilities addressed in the definition is one that is involved with
petroleum crude oil production and not any other type of oil
production, such as AFVO production. EPA's intent has always been that
the definition of production facility addresses petroleum crude oil
production, extraction, recovery, lifting, stabilization, separation or
treatment and associated storage or measurement. For example, the
definition includes terms associated with petroleum crude oil
production, such as gathering lines and flowlines which are exclusively
associated with upstream petroleum crude oil/gas production, not AFVO
production or processing facilities. The term ``oil or gas field'' is
used exclusively in upstream crude oil and gas production, not in AFVO
production. This language further clarifies that the definition of
production facility is specific to petroleum crude oil and gas
production operations rather than AFVO production.
    Several commenters expressed concern regarding multi-facility Plans
for oil production operations. The Agency does not intend to require an
owner or operator who uses one SPCC Plan to address multiple SPCC-
regulated facilities to aggregate the storage capacity of the
individual facilities covered in the multi-facility SPCC Plan. However,
the method in which an owner or operator defines the boundaries of
individual facilities must be consistent in determining both FRP and
SPCC applicability. The Agency believes that the changes to the
definitions of ``facility'' and ``production facility'' will not
discourage the use of multi-facility Plans because the Agency does not
require the aggregation of individual facility capacities covered under
a multi-facility Plan. To provide further clarity, EPA has removed the
limiting term ``single geographic'' from the production facility
definition. This change together with the other modifications finalized
in this action, make it clear that an owner or operator is not
compelled, by the definition of production facility, to aggregate
separate facilities located in a ``single geographic'' oil production
field into a single facility. If an owner or operator has several
distinct operations in one oil field, he is not required to consolidate
these operations into a single facility. On the other hand, the owner
or operator does have the flexibility to consolidate these operations
if he so chooses.
    To address the commenter's concerns that EPA is adding the terms
``intra-facility'' in front of the term gathering line, the Agency
notes that the addition of this term clarifies that EPA only regulates
those gathering lines located within a facility, as determined by the
owner or operator. The Agency disagrees with commenters who suggested
removing the term ``gathering lines'' from the production facility
definition to avoid dual jurisdiction. Gathering lines that are located
within the boundaries of an SPCC-regulated facility are considered to
be ``intra-facility gathering lines'' and are subject to EPA's
jurisdiction. However, EPA is exempting intra-facility gathering lines
subject to the regulatory requirements of DOT's pipeline regulations in
49 CFR parts 192 or 195 from this regulation. See section V.M.4 of this
notice for more information.
    EPA does agree that clarification on how these rules address
natural gas facilities is appropriate. In some cases, a natural gas
production facility may store condensate (petroleum oil) in quantities
that meet the applicability criteria for the SPCC requirements and
should be considered a production facility when determining
applicability of specific requirements in the rule (such as Sec.
112.9). In this final rule, therefore, EPA is adding the phrase
``(including condensate)'' to the definition. This clarification is
consistent with the current definition and provides additional clarity.
Gaseous phase hydrocarbons, such as natural gas, present at SPCC-
regulated facilities are not regulated under the SPCC rule. A detailed
explanation of this interpretation can be found at 69 FR 29729-29730,
May 25, 2004.
    EPA does not agree with the ``primary function'' approach to
determine the applicability to specific sections of the SPCC regulation
or the commenters' interpretation that, where geographic considerations
warrant, the definition of production facility should include all
infrastructure associated with activities and equipment that support
operations (such as base camps, airports, vehicle/equipment repair
operations, electrical generating facilities, construction equipment).
The definition of ``production facility'' is used to determine which of
the sections of the rule apply for these support operations. The
definition of production facility extends to all containers and
equipment directly related to the production of crude oil; it does not
include infrastructure (containers and equipment) not uniquely
associated with or in support of crude oil production. This is
consistent with the approach the Agency has taken in other EPA
regulations, such as the Resource Conservation and Recovery Act (RCRA)
Subtitle C regulations for oil and natural gas exploration, development
and production (53 FR 25447, July 6, 1988).

Thus, the Agency is clarifying in this notice that only the
infrastructure, containers and equipment uniquely associated with the
production of crude oil is subject to the specific requirements for a
production facility (Sec.  112.9). Containers, equipment and piping
containing crude oil used in the production, extraction, recovery,
lifting, stabilization, separation or treatment of oil or gas
condensate, or their associated storage or measurement is considered
part of an oil production facility and subject to the specific
requirements of Sec.  112.9. Specific examples of containers, piping or
equipment uniquely associated with or in support of the production of
crude oil include, but are not limited to: Well heads; flowlines and
intra-facility gathering lines; manifolds; heater treaters, free-water
knockout or other primary separation vessels; bulk storage containers
for crude oil or condensate; produced water containers; containers or
pits storing drilling fluids; drilling oil storage/use; containers used
for drilling completion operations; and hydraulic, dielectric, and
lubrication oils used exclusively to support oil production operations.
All other infrastructure or equipment that indirectly support crude oil
production must meet the specific bulk storage requirements under Sec.
112.8 or specific AFVO requirements under Sec.  112.12, as applicable.
(Any infrastructure and equipment at a facility subject to the SPCC
rule, whether in direct support of crude oil production operations, or
not, are also subject to the general rule requirements of Sec. Sec.
112.1-112.7.)
    For example, containers storing oil that support vehicle repair or
maintenance (such as gasoline, lubricating oil) at a production
facility are subject to both the general rule requirements and the
specific requirements of Sec.  112.8 because they are not directly or
uniquely associated with crude oil production. Similarly, heating oil
storage containers that support offices, oil storage to support
construction activities, oil storage in transformers or electrical
utility stations, or oil storage/processing to support refining
operations (for example, topping facilities) and other bulk storage or
the operational use of oil in containers, equipment and piping not used
in the production, extraction, recovery, lifting, stabilization,
separation or treatment of oil or gas condensate, or their associated
storage or measurement are not considered part of an oil production
facility and therefore are subject to both the general rule
requirements and the rule requirements for onshore facilities under
Sec.  112.8 (or Sec.  112.12 for AFVO).
    The 1971 MOU memorialized the agencies' intent to minimize
overlapping regulation by ``assign[ing] one agency the responsibility
for regulating a complete operation at any one facility.'' EPA and DOT
will revise the 2000 guidance memorandum, acknowledging that it has not
provided a clear basis for implementing the 1971 MOU or delineating EPA
and DOT jurisdiction (36 FR 24080, November 24, 1971). EPA will
continue its work to improve SPCC guidance for pipeline operators and
will communicate the results of discussions in a manner that affords
further opportunity for public comment.
2. Modifications to Sec.  112.9 for Drilling and Workover Facilities
    To clarify that drilling and workover activities are not subject to
the provisions at Sec.  112.9, EPA is amending the title of Sec.  112.9
to read ``Spill Prevention, Control, and Countermeasure Plan
requirements for onshore oil production facilities (excluding drilling
and workover facilities).'' EPA is also amending the introductory
sentence of the section accordingly.
    As described in the October 2007 proposed rule (72 FR 58378,
October 15, 2007), during the life of an oil well, maintenance or
remedial work may be necessary to improve productivity. A specialized
workover rig, and associated containers and equipment are brought on-
site to perform maintenance or remedial activities on the well.
Workover operations that perform maintenance or remedial activities on
oil wells are distinct from the normal production operations, and as
such are not subject to the requirements of Sec.  112.9, but are
subject to the applicable requirements in Sec.  112.10 (for onshore
facilities) or Sec.  112.11 (for offshore facilities). Workover
activities are a distinct operation and, if conducted by a separate
owner or operator, may be considered a separate mobile facility.
Workover facilities may have a different SPCC Plan, separate from the
production facility. EPA notes that although production activities may
temporarily cease during workover, if the production equipment and
containers (such as those found in a tank battery) remain in operation
or storing oil (that is, they are not ``permanently closed''), then the
production facility owner or operator must maintain his own SPCC Plan
during workover activities.
a. Comments
    Two commenters expressed support for EPA's clarification excluding
drilling and workover facilities from the provisions of Sec.  112.9.
b. Response to Comments
    The Agency agrees with the commenters and is finalizing the
amendment as proposed.
3. SPCC Plan Preparation and Implementation
    As described in the October 2007 proposed rule (72 FR 58378,
October 15, 2007), the variables associated with the start of
operations at new oil production facilities could lead to significant
changes in necessary storage capacity and facility design. In this
rulemaking, EPA is finalizing an amendment to allow a new oil
production facility (that is, one that becomes operational after July
1, 2009) a period of six months after the start of operations to
prepare and implement an SPCC Plan. EPA is excluding oil production
facilities from the current requirements at Sec.  112.3(b)(1), and is
adding a new paragraph at Sec.  112.3(b)(3) to require the owner or
operator of a new oil production facility to prepare and implement an
SPCC Plan six months after the start of operations.
    The rule amendment applies at a new oil production facility that
begins operating after July 1, 2009. The amendment does not apply to
drilling or workover activities at a production facility. Drilling and
workover operations are subject to the requirements at Sec.  112.3(c)
for mobile facilities and may implement a general SPCC Plan. Therefore,
both during the initial drilling of the well, as well as during any
workover activity, there are measures required for spill prevention and
response for any oil discharges that occur from a drilling or workover
facility subject to this rule. This amendment would not apply to an
existing production facility in which a new well is drilled, and added
to the existing tank battery/facility. In this case, the facility owner
or operator must amend the SPCC Plan in accordance with Sec.  112.5(a),
which requires the Plan to be amended within six months of the facility
change, and implementation within six months of the amendment.
    With this amendment, EPA recognizes that for some oil fields, based
on the often variable conditions of the oil reservoir, the type and
proportion of products may be uncertain until after the process of
extraction has started. During this timeframe, additional equipment may
be added or removed

from the facility which would require an amendment to the SPCC Plan and
the owner or operator of a new oil production facility may need to make
multiple revisions to the Plan. The Agency believes that allowing a new
oil production facility six months after the start of operations to
prepare and implement an SPCC Plan properly addresses these concerns.
The ``start of operations'' for an oil production facility is indicated
by the start of well fluid pumping, transfer via flowlines, separation,
treatment or storage of crude oil, or the storage of other oils in
capacities that exceed the rule's current oil storage capacity
thresholds for applicability.
a. Comments
    Several commenters expressed support for EPA's proposed amendment
to allow new oil production facilities six months to prepare and
implement an SPCC Plan. Two commenters, however, suggested that EPA
allow owners and operators one year for sufficient time for Plan
preparation and implementation. Another commenter suggested that EPA
provide an automatic extension for a facility owner or operator based
on his inability to obtain the services of a PE.
b. Response to Comments
    The Agency agrees with those commenters supporting an extension of
six months to the timeframe by which an oil production facility must
prepare and implement an SPCC Plan. The Agency disagrees with the
suggested alternative of one year for the owner or operator to prepare
and implement an SPCC Plan after the start of production operations.
The Agency recognizes the unique characteristics of an oil production
facility, but given that an oil production facility is likely to
stabilize operations within six months from start-up, a one-year time
period for Plan preparation and implementation is inappropriate. If a
facility owner or operator needs additional time to prepare and
implement the SPCC Plan, the existing rule already provides the owner
or operator the opportunity to request an extension of time to come
into compliance in accordance with Sec.  112.3(f) when circumstances
are beyond his control. This may occur, for example, when there are no
qualified personnel available or if there are equipment delivery
delays.
4. Flowlines and Intra-Facility Gathering Lines
    EPA is finalizing a conditional exemption from secondary
containment requirements under the SPCC rule for flowlines and intra-
facility gathering lines. That is, in lieu of general secondary
containment, an owner or operator may opt to prepare a contingency plan
and written commitment of manpower, equipment, and materials.
Additionally, EPA is finalizing specific requirements for a flowlines
and intra-facility gathering lines maintenance program. EPA is also
exempting intra-facility gathering lines that are subject to the
regulatory requirements at 49 CFR parts 192 or 195 from the SPCC
requirements. EPA is not promulgating definitions of flowlines and
intra-facility gathering lines in this action.
a. Definition of Flowline and Intra-Facility Gathering Line and
Exemption
    In the October 2007 proposal (72 FR 58378, October 15, 2007), EPA
requested comments as to whether regulatory definitions for
``flowline'' and ``intra-facility gathering line'' are necessary, and
if so, suggestions for appropriate definitions. This request was
intended to determine whether clarification of the scope of the terms
and their applicability under the SPCC rule was necessary. EPA
indicated in the proposal that the Agency did not believe that such
definitions were necessary because there is a common understanding of
these terms within the affected industry. The Agency is clarifying the
scope of the SPCC rule's applicability to gathering lines and
finalizing an amendment that exempts the ``intra-facility'' gathering
lines that are subject to both EPA and DOT regulatory requirements from
the SPCC rule in response to comments on the proposed conditional
exemption from secondary containment requirements for flowlines and
intra-facility gathering lines. The Agency believes that this exemption
is a logical outgrowth of the proposal and the comments received. In
the October 2007 proposal, EPA acknowledged that given the
characteristics of certain intra-facility gathering lines, these
pipelines may be regulated under requirements of both EPA and DOT (72
FR 58407, October 15, 2007). EPA also recognized in the proposal that
DOT requirements for pipelines may be similar in scope to SPCC
regulations, so that compliance with DOT requirements may be considered
environmentally equivalent to certain SPCC requirements. EPA also
recognized in the proposal that DOT requirements for pipelines may be
similar in scope to SPCC regulations, so that compliance with DOT
requirements may be considered environmentally equivalent to certain
SPCC requirements. DOT has promulgated regulations for pipelines under
49 CFR parts 192 (Transportation of Natural and Other Gas by Pipeline),
194 (Response Plans for Onshore Oil Pipelines) and 195 (Transportation
of Hazardous Liquids by Pipeline). DOT has the statutory authority over
gas or hazardous liquid pipelines of any diameter within
environmentally sensitive rural areas (defined as ``unusually sensitive
areas''), and liquid pipelines above six inches in diameter operating
at low pressure. While many gathering lines are under DOT's statutory
authority, only a subset of them has DOT regulatory requirements.
    EPA recognizes that gathering lines can be outside the Agency's
jurisdiction because they ``transport'' oil outside of an oil
production facility. EPA has jurisdiction only over non-transportation-
related facilities, which includes pipelines that transport oil within
a facility. Any inter-facility pipeline, including a gathering line,
that transports oil between facilities or from a facility to a vessel,
or from a facility to a transportation-related pipeline facility, such
as a transmission line, or a pipeline breakout tank, is considered
transportation-related and is therefore outside the jurisdiction of EPA
and not subject to the SPCC rule. However, the definition of
``facility'' as it applies to the SPCC rule is flexible. Depending upon
how an owner/operator defines his facility under the SPCC rule, an oil
production facility may also include gathering lines. While gathering
lines within the SPCC facility boundaries are intra-facility piping,
EPA is maintaining the term intra-facility gathering lines because it
is a term that is well recognized within the production sector. For
those intra-facility gathering lines that are regulated by both EPA and
DOT, EPA is exempting them from the SPCC requirements. In other words,
the exemption is for intra-facility gathering lines present at a
facility where the piping is subject to both EPA and DOT jurisdiction
and regulations. EPA's focus with the SPCC rule is the regulation of
oil storage at facilities engaged in activities related to drilling,
producing, gathering, processing, refining, transferring, distributing
and use of oil, while DOT's focus is in the area of pipeline
regulation; therefore, EPA believes it is appropriate to defer to DOT's
technical regulation in lieu of EPA's intra-facility gathering line
requirements. EPA believes this change is appropriate and is a logical
outgrowth of the proposal and several comments received regarding
jurisdiction of intra-facility gathering lines.
    Only those lines that are subject to DOT regulations are eligible
for the exemption finalized in this action.

Those intra-facility gathering lines located at a facility that are not
subject to the regulatory requirements at 49 CFR parts 192 and 195
remain subject to the requirements in 40 CFR part 112. Other equipment
and piping at an oil production facility (such as flowlines), remain
subject to the SPCC requirements. In addition, this exemption requires
that owners or operators of a facility identify and mark as ``exempt''
the location of exempt piping on the facility diagram. This requirement
will assist facility and EPA personnel in defining the boundaries of
EPA and DOT jurisdiction and provide response personnel with
information used to identify hazards during a spill response activity.
    As discussed in Section V.D of this notice, an owner or operator
has the flexibility under the definition of facility to determine the
boundaries of their SPCC facility; thus, the facility may include
intra-facility gathering lines. DOT defines a production facility under
49 CFR parts 195 as ``piping or equipment used in the production,
extraction, recovery, lifting, stabilization, separation or treating of
petroleum or carbon dioxide, or associated storage or measurement. (To
be a production facility under this definition, piping or equipment
must be used in the process of extracting petroleum from the ground,
and preparing it for transportation by pipeline.)'' (49 CFR 195.2) This
definition is similar in scope to EPA's definition of production
facility described above. However, DOT provides additional specificity
regarding the endpoints of a production operation for the purpose of
defining a gathering line. Under 49 CFR part 192, DOT clarifies that
the beginning of gathering may not extend beyond the furthermost
downstream point in a production operation (49 CFR 192.8(a)(1)).
    Comments. Two commenters suggested clarifications of the term
flowline, one of whom suggested a definition. Two other commenters
stated that definitions for flowline or intra-facility gathering line
were not needed, while several commenters suggested that the references
to ``gathering lines'' with flowlines be eliminated, citing the
confusion of using the term and noting the MOU with DOT, which
specifically limits EPA's jurisdiction of these lines. Another
commenter requested that EPA clarify that post-separation gas gathering
lines are exempt from the SPCC rule. One other commenter suggested that
EPA modify Sec.  112.1(d)(1)(ii) to include an exemption for all
gathering lines.
    Response to comments. EPA disagrees with those commenters that
suggest there is a need to define the terms ``flowline'' and
``gathering line.'' EPA believes the oil production sector has a common
understanding of these terms and that specific definitions are not
needed. ``Flowlines'' are piping that transfer crude oil and well
fluids from the wellhead to the tank battery where separation and
treatment equipment are typically located. Flowlines may also connect a
tank battery to an injection well. Depending on the size of the oil
field, flowlines may range in diameter and run from hundreds of feet to
miles between the wellheads and the tank batteries or primary
separation operations. The term ``gathering lines'' refers to piping or
pipelines that transfer crude oil product between tank batteries,
within or between facilities. Gathering lines often originate from an
oil production facility's lease automatic custody transfer (LACT) unit,
which transfers oil to other facilities involved in gathering, refining
or pipeline transportation operations.
    EPA considers gathering lines subject to EPA's jurisdiction if they
are located within the boundaries of an otherwise regulated SPCC/FRP
facility (that is, intra-facility gathering lines). Therefore, to
address the concerns raised by commenters, the Agency is including the
phrase ``intra-facility'' in front of the term gathering lines to
clarify that EPA only has the authority to regulate piping, in this
case intra-facility gathering lines, which are located within a
facility boundary. The Agency also is finalizing an amendment that
excludes from regulation those ``intra-facility'' gathering lines
subject to both EPA and DOT regulatory requirements. Specifically, one
commenter suggested that EPA modify Sec.  112.1(d) to include an
exemption for all gathering lines. While EPA does not agree that all
intra-facility gathering lines, located within a production facility,
should be excluded from the SPCC requirements, the Agency does agree
that minimizing dual regulation, where appropriate, is beneficial to
the regulated community. Therefore, EPA is finalizing a new exemption
under Sec.  112.1(d)(2)(i) and 112.1(d)(11) for intra-facility
gathering lines subject to DOT regulation. The Agency believes this
change is appropriate and is a logical outgrowth of the proposal and
several comments received regarding jurisdiction of intra-facility
gathering lines.
    However, the Agency does not want to create a regulatory ``gap''
with this action. Gathering lines, as well as flowlines are a source of
oil spills, as demonstrated in EPA's study of the exploration and
production sector, ``Considerations for the Regulation of Onshore Oil
Exploration and Production Facilities Under the Spill Prevention,
Control, and Countermeasure Regulation (May 30, 2007; located in the
docket for this rulemaking: EPA-HQ-OPA-2007-0584-0015). Currently, EPA
has only a limited set of requirements for flowlines and intra-facility
gathering lines, whereas DOT has more comprehensive requirements for
pipelines (which are only applicable to a subset of gathering lines
within DOT jurisdiction). Additionally, there are no industry standards
for flowline or gathering line maintenance. Therefore, intra-facility
gathering lines located at a facility that are not subject to the
regulatory requirements under 49 CFR parts 192 or 195 remain subject to
EPA's SPCC regulations under 40 CFR part 112. These lines also remain
subject to EPA jurisdiction and the Agency, if appropriate, can use
existing rule mechanisms under Sec.  112.1(f) to bring exempted intra-
facility gathering lines back under the SPCC rule requirements.
    One commenter requested that EPA clarify that post-separation gas
gathering lines are exempt from the rule. EPA maintains its position
that hydrocarbons in a gaseous phase under ambient temperature and
pressure, such as natural gas, are not regulated under the SPCC rule.
However, production facilities can include piping with both oil and gas
phases. In this instance, such a facility's dual-phase flowlines and
intra-facility gathering lines (that is, those carrying both gas and
liquid phase hydrocarbon) are subject to the SPCC requirements (unless
they are subject to 49 CFR parts 192 or 195 and are therefore exempt)
because if the lines were to rupture or leak, they may discharge oil to
navigable waters or adjoining shorelines in quantities that may be
harmful as defined in 40 CFR part 110.
b. Exemption From Secondary Containment
    EPA believes that secondary containment is, in most cases,
impracticable for flowlines and intra-facility gathering lines.
Therefore, the Agency is amending Sec.  112.7(c) to provide an
alternative (which is optional) to the general secondary containment
requirements for flowlines and intra-facility gathering lines (unless
they are exempt from regulation). In lieu of secondary containment, the
Agency will require the implementation of an oil spill contingency plan
in accordance with 40 CFR part 109 (Criteria for State, Local and
Regional Oil Removal Contingency Plans) and a written

commitment of manpower, equipment, and materials required to
expeditiously control and remove any quantity of oil discharged that
may be harmful, without having to make an impracticability
determination for each piece of piping. The Agency is tailoring the
requirements in an effort to improve compliance and enhance
environmental protection.
    Comments. Several commenters expressed support for EPA's proposed
amendment to remove the secondary containment requirements for
flowlines and intra-facility gathering lines at oil production
facilities. Several commenters requested, however, that EPA acknowledge
the option for owners or operators to select sized secondary
containment based on site conditions and recommendations of the PE
under certain circumstances. One commenter suggested a modification to
allow collection areas rather than individual containment along
gathering lines. Another commenter, however, stated that the proposed
amendment to exempt flowlines and intra-facility gathering lines at oil
production facilities from the secondary containment requirements is
inconsistent with 33 U.S.C. 1321(j)(5)(D).
    Response to comments. EPA agrees with the majority of commenters
that secondary containment for flowlines and intra-facility gathering
lines is, in most cases, impracticable and that providing secondary
containment for these lines can be difficult and expensive for an owner
or operator. Flowlines and intra-facility gathering lines are often
several miles long, can be buried, can extend far from the main
facility, and are often placed across land that is not owned by the
owner or operator of the oil production facility. Providing secondary
containment structures for these lines may result in soil erosion and
negative impacts to the land (such as when they are located in farm
fields). Buried flowlines present additional difficulty, because their
exact location may be uncertain, especially at an oil production
facility that has changed ownership since the original installation of
the lines.
    The Agency also recognizes that some facilities have already
installed containment for flowlines and intra-facility gathering lines
and therefore should not be required to provide a contingency plan in
addition to secondary containment. Therefore, EPA agrees with those
commenters who suggested that the requirement for a contingency plan in
lieu of secondary containment should be an option.
    Contingency planning is one of the many tools that the Agency has
provided in the SPCC regulatory requirements. The Agency disagrees with
the comment arguing that a contingency plan requirement is inconsistent
with the intent of 33 U.S.C. 1321(j)(5)(D). The Agency's authority to
promulgate the SPCC regulations is found in Section 311(j)(1)(C) of the
Clean Water Act, 33 U.S.C. 1321(j)(1)(C). Section 311(j)(1)(C) requires
the President to issue regulations establishing procedures, methods,
equipment, and other requirements to prevent discharges of oil to
navigable waters or adjoining shorelines from vessels and facilities
and to contain such discharges. The statutory provision gives the
Agency broad discretion to establish the requirements under the SPCC
rule. Also, Section 311(j)(5)(D), 33 U.S.C. 1321(j)(5)(D), lists the
requirements for facility response plans. The Agency has promulgated
regulations for facility response plans in 40 CFR 112.20 and 112.21.
The purpose of the SPCC program is to prevent and control oil
discharges from reaching navigable waters or adjoining shorelines.
However, it is important to recognize that despite best prevention
efforts, discharges may occur. The contingency plan requirements under
the SPCC program have dual purposes. They include components to prevent
oil that has escaped its container or secondary containment from
reaching navigable waters or adjoining shorelines, and also include
components that address the timely and appropriate response actions to
be implemented when an oil discharge does impact navigable waters or
adjoining shorelines.
c. Contingency Plan in Lieu of Secondary Containment
    EPA is amending Sec. Sec.  112.7(c) and 112.9(d)(3) to provide an
alternative to the secondary containment requirements for flowlines and
intra-facility gathering lines at an oil production facility. In lieu
of secondary containment, a facility owner or operator may opt to
implement an oil spill contingency plan in accordance with 40 CFR part
109 (Criteria for State, Local and Regional Oil Removal Contingency
Plans) and prepare a written commitment of manpower, equipment, and
materials required to expeditiously control and remove any quantity of
oil discharged that may be harmful, without having to make an
impracticability determination for each piece of piping. The Agency is
amending this provision in an effort to improve compliance and enhance
environmental protection. The use of a contingency plan does not
relieve the owner or operator of liability associated with an oil
discharge to navigable waters or adjoining shorelines that violates the
provisions of Section 311(b)(3) of the Clean Water Act, 33 U.S.C.
1321(b)(3). EPA is also amending Sec.  112.7(a) to make it clear that
the contingency plan provisions under Sec.  112.9(d)(3) are not subject
to the environmental equivalence provision.
    Comments. Several commenters expressed support for EPA's proposal
to require an oil spill contingency plan in lieu of secondary
containment. One commenter, however, suggested an option to require
annual physical inspections and the installation of isolation valves.
Two other commenters requested that EPA reduce the burden of using this
alternative option, because the documentation effort for a contingency
plan is extensive.
    Response to comments. The Agency does not agree that annual
physical inspections and the installation of isolation valves are
appropriate, because this could prove to be impracticable for some
lines, specifically those that are buried.
    With respect to the comments regarding the additional burden that a
contingency plan requirement would impose on facilities, the Agency
recognizes that this amendment would require additional documentation.
However, EPA believes that a contingency plan is necessary when
secondary containment is not provided. This final rule allows the owner
or operator of the facility to develop a contingency plan as an option
to general secondary containment. The contingency plan required when
secondary containment is not practicable for flowlines and intra-
facility 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
ensure quick availability and deployment of response equipment. The
complexity or simplicity of a facility's contingency plan is subject to
good engineering practice as determined by the certifying PE. EPA
developed a model contingency plan as part of the SPCC Guidance for
Regional Inspectors. This model plan is intended only as an example and
inspectors should only use the document for this purpose. Additionally,
EPA acknowledges that given the characteristics of certain intra-
facility gathering lines, these pipelines may be regulated under
requirements of both EPA and DOT. Because DOT requirements for
pipelines may be similar in purpose and scope, EPA

recognizes that compliance with the DOT requirements (for example, 49
CFR part 194) for these gathering lines may be considered to satisfy
the contingency planning requirement. Therefore a contingency plan
developed for 49 CFR part 194 may serve to meet the SPCC Plan
requirements. In addition, as previously discussed, the Agency is
exempting intra-facility gathering lines that are subject to the
regulatory requirements under 49 CFR part 192 or 195 from 40 CFR part
112. Furthermore, the owner or operator of an oil production facility
who has prepared an FRP under Sec.  112.20 satisfies the contingency
planning requirement for flowlines and intra-facility gathering lines
because an FRP is more comprehensive than a contingency plan under 40
CFR part 109. If such a facility owner or operator has already
developed an FRP to comply with Sec.  112.20, then he does not need to
develop a contingency plan in accordance with 40 CFR part 109. The
certifying PE must ensure that the FRP is adequate for the facility and
prepared in accordance with good engineering practice. Similarly, the
owner or operator of an oil production facility who has prepared a
state spill or pollution prevention contingency plan that meets the
requirements of 40 CFR part 109 may opt to use this state plan to
comply with the SPCC contingency plan requirements.
    It should also be noted that the contingency planning requirement
is an alternative to the requirement for general secondary containment
for flowlines and intra-facility gathering lines and the facility owner
or operator can decide which option to comply with. The purpose of this
action is to provide options and streamlined requirements that should
improve compliance with the rule. The Agency recognizes that flowlines
and intra-facility gathering lines are a source of oil discharges and
believes that this action provides an alternative method for owners/
operators to develop spill prevention and response practices for this
equipment to maintain environmental protection.
d. Requirements for a Flowline and Intra-Facility Gathering Line
Maintenance Program
    EPA is amending the requirement for an owner or operator to prepare
and implement a written flowline and intra-facility gathering line
maintenance program under Sec.  112.9(d)(4). This action specifies that
the requirements apply to intra-facility gathering lines, as well as
flowlines at an oil production facility. Intra-facility gathering lines
pose the same potential for discharge as flowlines. EPA never intended
to regulate the two types of piping differently. Under the amended
provisions, a maintenance program must address procedures to:
     Ensure that such flowlines and intra-facility gathering
lines and associated valves and equipment are compatible with the type
of production fluids, their potential corrosivity, volume, and
pressure, and other conditions expected in the operational environment.
     Visually inspect and/or test flowlines and intra-facility
gathering lines and associated appurtenances on a periodic and regular
schedule for leaks, oil discharges, corrosion, or other conditions that
could lead to a discharge as described in Sec.  112.1(b). The frequency
and type of testing must allow for the implementation of a contingency
plan as described under part 109 of this chapter, if there is no
secondary containment.
     Take corrective action or make repairs to any flowlines
and intra-facility gathering lines and associated appurtenances as
indicated by regularly scheduled visual inspections, tests, or evidence
of a discharge.
     Promptly remove or initiate actions to stabilize and
remediate any accumulations of oil discharges associated with
flowlines, intra-facility gathering lines, and associated
appurtenances.
    Comments. Several commenters expressed support for EPA's proposed
revisions to the flowline/intra-facility gathering line program,
although some commenters suggested the addition of corrosion protection
for these lines. A number of commenters expressed concern that the
requirement for a contingency plan and maintenance program would be
burdensome. Some of these commenters suggested using a maintenance
program based on risk levels and good industry practices, as determined
by a PE. Another commenter requested that the current language be
maintained for a program of flowline maintenance.
    Other commenters provided suggested other revisions. Specifically,
some commenters provided alternative language for the provisions under
Sec.  112.9(d)(4). One commenter stated that the proposed requirement
under the design and development requirements of Sec.  112.9(d)(4)(i)
is vague and unnecessary given the responsibility of a PE certifying
the Plan. Other commenters also suggested adding language that would
acknowledge that other methods of immobilizing hydrocarbons in soil
matrices such as physical, chemical and/or biological treatment methods
to address oil accumulations associated with flowlines rather than
``prompt removal.'' Finally, commenters expressed concern with the
phrase ``promptly remove'', as associated with actions to stabilize and
remediate any accumulations of oil discharges. Commenters suggested
replacing this phrase with ``upon discovery''.
    Response to comments. EPA is finalizing the amended requirements
for a flowline and intra-facility maintenance program under Sec.
112.9(d)(4), specifying that the requirements apply to intra-facility
gathering lines, as well as flowlines at an oil production facility.
The Agency believes that an effective flowline maintenance program is
necessary to detect a discharge in a timely manner so that the oil
discharge response operations described in the contingency plan may be
implemented effectively. Additionally, eliminating the requirement for
secondary containment necessitates more prescriptive requirements for
discharge prevention to ensure the integrity of the primary containment
of the pipe itself.
    EPA is finalizing requirements under Sec.  112.9(d)(4) to require a
performance-based program of flowline and intra-facility gathering line
maintenance that addresses the facility owner or operator's procedures,
that must be documented in their SPCC Plan. EPA agrees with several
comments on the language associated with these requirements and has
made several changes to the proposed rule in response to these
comments. EPA is finalizing the requirement under Sec.  112.9(d)(4)(iv)
with some modifications to the proposed regulatory text. The finalized
rule states: ``Promptly remove or initiate actions to stabilize and
remediate any accumulations of oil discharges associated with
flowlines, intra-facility gathering lines, and associated
appurtenances.'' This measure is intended to ensure the removal of oil
accumulations in order to prevent a discharge. The Agency disagrees
with the comment that suggested replacing ``Promptly remove'' with
``Upon discovery.'' ``Promptly remove'' indicates that the owner or
operator of the facility has both the responsibility and flexibility to
outline an inspection program under Sec.  112.9(d)(4)(ii) which puts
the timeframe for ``prompt removal'' in the context of the inspection
frequency. Commenters also suggested, however, that language be added
that would acknowledge that other methods of immobilizing

hydrocarbons in soil matrices, such as physical, chemical and/or
biological treatment methods can be used. The Agency agrees that other
methods may be used to stabilize and remediate, and thus, the
regulatory text has been revised by adding the phrase, ``remove or
initiate actions to stabilize and remediate'' to the rule. EPA
considers the removal of oil-contaminated soil as a method to prevent
oil from becoming a discharge as described in Sec.  112.1(b). Disposal
of oil must be in accordance with applicable Federal, state, and local
requirements; under Sec.  112.7(a)(3)(v), a facility owner or operator
is required to describe the methods of disposal of recovered materials
in accordance with applicable legal requirements. For the purposes of
this provision, EPA believes that the removal of recoverable oil can be
combined with physical, chemical, and/or biological treatment methods
to address any residual oil. These treatment methods must be consistent
with other Federal, state or local requirements as applicable, and must
be properly managed to prevent a discharge as described in Sec.
112.1(b).
    EPA believes that the variations in production facility piping
design, layout and location makes flexibility important in order to
encourage compliance with this requirement, and believes that this
flexibility is already available. However, the flowline and intra-
facility gathering line maintenance program requirements also are
subject to the environmental equivalence provision found at Sec.
112.7(a)(2). That is, the facility owner or operator may deviate from
the requirements if an environmentally equivalent alternate measure is
implemented. EPA recognizes that other Federal or state requirements
may be environmentally equivalent to certain SPCC requirements,
including the flowline and intra-facility gathering line maintenance
program requirement. An environmental equivalence determination is
subject to review and certification by a PE.
5. Flow-Through Process Vessels
    EPA is modifying the requirements at Sec.  112.9(c) to provide an
alternative to the sized secondary containment requirements for flow-
through process vessels at oil production facilities. Flow-through
process vessels, such as horizontal or vertical separation vessels--for
example, heater-treater, free-water knockout, gun-barrel, etc.--have
the primary purpose of separating the oil from other fractions (water
and/or gas) and sending the fluid streams to the appropriate container.
Specifically, in lieu of sized secondary containment, a facility owner
or operator may opt to provide general secondary containment, inspect
or test flow-through process vessels and components for leaks,
corrosion or other conditions that could lead to a discharge, as
described in Sec.  112.1(b), promptly remove or initiate actions to
stabilize and remediate any oil accumulations, and take corrective
action should a discharge occur. EPA also would require that sized
secondary containment be installed if the facility discharges more than
1,000 U.S. gallons of oil in a single discharge as described in Sec.
112.1(b), or discharges more than 42 U.S. gallons of oil in each of two
discharges as described in Sec.  112.1(b) within any twelve month
period, from flow-through process vessels (excluding discharges that
are the result of natural disasters, acts of war, or terrorism) within
six months of such a discharge.
    EPA is taking this action because the Agency agrees with concerns
regarding the requirement to provide sized secondary containment around
flow-through process vessels, such as heater-treaters, due to a
potential fire hazard if spilled oil collects around such equipment.
EPA also recognizes that similar flow-through process equipment (i.e.,
oil-filled manufacturing equipment, such as reaction vessels,
fermentors, high pressure vessels, mixing tanks, dryers, heat
exchangers, and distillation columns) at non-production facilities are
not subject to the more stringent sized secondary containment and
inspection requirements required for bulk storage containers; only the
general secondary containment requirements at Sec.  112.7(c) apply.
However, EPA recognizes that process equipment at non-production
facilities, such as at manufacturing facilities, is typically attended
during hours of operation and there is a greater potential to
immediately discover and correct a discharge at non-production
facilities than at oil production facilities, which are generally
unattended. Therefore, EPA is requiring additional measures for flow-
through process vessels at oil production facilities that do not have
sized secondary containment, including inspection or testing of
components, prompt removal or initiation of actions to stabilize and
remediate any oil accumulations, and corrective action.
a. Exemption From Sized Secondary Containment
    EPA is amending the requirements in Sec.  112.9(c)(2) to add the
phrase ``Except as described in paragraph (c)(5) of this section for
flow-through process vessels'' at the beginning of the provision. This
amendment removes the requirement to provide sized secondary
containment for flow-through process vessels at oil production
facilities without making an impracticability determination, and allows
the facility owner or operator the option to comply with the alternate
requirements in Sec.  112.9(c)(5) instead.
    The general secondary containment requirement of Sec.  112.7(c)
still applies to flow-through process vessels; they must be provided
with secondary containment so that any discharge does not escape the
containment system before cleanup occurs. As described in Section V.H
of this notice, EPA is amending Sec.  112.7(c) to clarify that the
provision allows for the use of both active and passive secondary
containment measures to prevent a discharge to navigable waters or
adjoining shorelines. Active containment measures are those that
require deployment or other specific action by the operator. These
measures may be deployed either before an activity involving the
handling of oil starts, or in reaction to a discharge, so long as the
active measure is designed to prevent an oil discharge from reaching
navigable waters or adjoining shorelines. However, active measures
would generally have limited applicability at oil production facilities
because these facilities are typically not attended and owners or
operators may not be able to detect a discharge in a timely manner to
successfully implement the active measures. In contrast, passive
measures are installations that do not require deployment or action by
the owner or operator and may be more appropriate for unattended
production operations. The SPCC Guidance for Regional Inspectors
provides several examples of the use of active and passive measures at
an SPCC-regulated facility.
    With this action, owners or operators of oil production facilities
are no longer required to locate flow-through process vessels within a
secondary containment system sized for the entire capacity of the
largest single container and sufficient freeboard to contain
precipitation. However, EPA believes that oil production facility
owners and operators may want to provide secondary containment (such as
berms) around the entire tank battery, as many oil production
facilities currently do. These batteries can include flow-through
process vessels, such as separators, along with oil stock tanks and
other bulk storage containers. Such a facility design would provide the
maximum environmental protection.
    Comments. Several commenters expressed support for EPA's
alternative option for flow-through process vessels

in lieu of sized secondary containment. Two commenters, however,
requested that EPA clarify whether secondary containment is an
alternative to the proposed option, while one commenter requested
clarification on whether EPA means containment would hold the single
largest process vessel and not containment sized to hold all vessel
fluids. Another commenter expressed concern that the proposed
requirements are burdensome; DOE generally supported that position and
encouraged EPA to consider existing state regulatory programs in lieu
of additional requirements.
    Another commenter expressed concern that flow-through process
vessels at production facilities cause pollution that can not be
remediated to the pre-spill condition. Still another commenter was
concerned that more oil than the contents of the vessels may be
discharged because oil may be constantly flowing into these vessels
from the wells. Finally, one commenter expressed concern that the
proposed exemption from sized secondary containment is inconsistent
with 33 U.S.C. 1321(j)(5)(D), which the commenter believes requires
every SPCC Plan to identify the resources necessary to ``mitigate or
prevent a substantial threat of'' a worst case discharge. The commenter
expressed concern that general secondary containment for a ``most
likely'' spill would fail to prevent the worst case discharge.
    Response to comments. EPA recognizes that some facilities have
already provided sized secondary containment in accordance with Sec.
112.9(c)(2) for flow-through process vessels at productions facilities.
EPA agrees with commenters that facility owners or operators who have
installed such containment should not be required to comply with the
additional requirements for these vessels. Therefore, EPA is amending
the rule to indicate that flow-through process vessels equipped with
sized secondary containment in accordance with Sec.  112.9(c)(2) and
(c)(3) are not required to comply with the alternate requirements under
Sec.  112.9(c)(5).
    In response to the commenter who asked about the size of
containment required, EPA notes that in determining how to provide
appropriate general secondary containment for flow-through process
vessels, a production facility owner or operator may consider the
typical failure mode and most likely quantity of oil that would be
discharged (see Sec.  112.7(c)). Based on these site-specific
conditions, the owner or operator can determine what capacity of
secondary containment is needed, and design the containment method
accordingly. The design for general secondary containment should
address site-specific factors, including, but not limited to, frequency
of site visits, rate of flow of the wells, capacity of the containers,
and whether the facility is equipped with automatic shut-off devices to
prevent an overflow. However, as discussed elsewhere in this preamble,
general secondary containment is based on the most likely discharge,
not the worst case discharge. EPA agrees with the commenter who
expressed concern regarding the effects of a discharge from flow-
through process vessels, but the Agency believes that this alternative
approach, which requires general secondary containment in accordance
with Sec.  112.7(c) and the additional requirements to inspect, repair
equipment, and address oil accumulations that may occur following a
discharge from flow-through process vessels, addresses this concern.
The Agency also believes the alternative requirements for flow-through
process vessels address the concern that these facilities are
constantly operating and have constant flow of fluids through this
equipment because the owner or operator must inspect the equipment and
take corrective action to address a discharge following procedures
described in the SPCC Plan.
    As part of this action, EPA considered whether existing state
regulatory programs could satisfy the amended requirements. Although a
number of states do have requirements for oil production facilities to
prevent spills, they do not provide a comprehensive, national approach
that would be equivalent to the SPCC requirements, as these programs
have been developed to meet states' individual goals. Therefore, EPA
believes that relying solely on state programs would not provide
nationwide consistent requirements for spill prevention. However, the
Agency recognizes the benefits of allowing the owner or operator of a
regulated facility to take credit for compliance with state program
requirements when these serve to meet certain SPCC requirements and can
be referenced in accordance with 40 CFR part 112.
    The Agency also disagrees with those commenters who characterized
the amended requirements as excessive, and the requests for EPA to
reconsider the necessity of additional measures in lieu of sized
secondary containment. The amendment allows an owner or operator to
provide general secondary containment for flow-through process vessels
and requires new prevention measures as an alternative to the rule's
existing sized secondary containment requirement. The alternative
measures are optional--that is, the owner or operator may still choose
to comply with the sized secondary containment requirement, and the
facility owner or operator decides which option is best suited to the
design and operation of the facility. The Agency believes that the
alternative approach finalized in this rule for flow-through process
vessels allows the owner or operator of an oil production facility
flexibility in how to design secondary containment for this equipment
and in how to comply with the additional requirements that maintain
environmental protection.
    The Agency disagrees with the commenter who argued that the revised
option for flow-through process vessels at production facilities is
inconsistent with the intent of 33 U.S.C. 1321(j)(5)(D). The Agency's
authority to promulgate the SPCC regulations is found in Section
311(j)(1)(C) of the Clean Water Act, 33 U.S.C. 1321(j)(1)(C). Section
311(j)(1)(C) requires the President to issue regulations establishing
procedures, methods, equipment, and other requirements to prevent
discharges of oil to navigable waters and adjoining shorelines from
vessels and facilities and to contain such discharges. The statutory
provision gives the Agency broad discretion to establish the
requirements under the SPCC rule. The purpose of the SPCC program is to
prevent and control oil discharges from reaching navigable waters or
adjoining shorelines. Also, Section 311(j)(5)(D), 33 U.S.C.
1321(j)(5)(D), lists the requirements for facility response plans. The
Agency has promulgated regulations for facility response plans in 40
CFR 112.20-21and this action does not impact the requirement for an
owner/operator to prepare and implement an FRP when the facility meets
the substantial harm criteria in Sec.  112.20(f). Therefore, this
amendment does not conflict with the requirements under 33 U.S.C. 1321
(j)(5)(D).
b. Additional Requirements
    Because oil production facilities are typically unattended while
operating, EPA is adding a provision at Sec.  112.9(c)(5) to provide
additional requirements for flow-through process vessels at those
facilities that do not provide sized secondary containment. These
additional requirements include periodic inspection and/or testing for
leaks, corrosion, or other conditions that could lead to a discharge as
described in Sec.  112.1(b); corrective action or repairs to flow-
through process vessels and any associated components as indicated by

regularly scheduled visual inspections, tests, or evidence of an oil
discharge; and prompt removal or initiation of actions to stabilize and
remediate any accumulations of oil discharges associated with flow-
through process vessels.
    Comments. One commenter recommended not mandating routine
inspection of flow-through vessels, because oil and gas operators
routinely visit tank batteries and wells and the lease operator would
observe leaks from the vessels. The commenter also stated that weather
conditions require aerial inspections during the winter months, which
may not be possible given the proposed requirement. Another commenter
expressed concern with the burden of complying with the additional
inspection requirements.
    Several commenters provided alternative language for promptly
removing any accumulations of oil discharges as described under Sec.
112.9(c)(5). Specifically, commenters suggested adding language that
would acknowledge other methods of immobilizing hydrocarbons in soil
matrices (such as physical, chemical and/or biological treatment
methods) to address oil accumulations associated with flowlines.
Commenters also expressed concern with the phrase ``promptly remove''
and suggested replacing it with the phrase ``upon discovery.''
    Response to comments. The requirement of periodic inspection and/or
testing of flow-through process vessels and associated appurtenances on
a regular schedule for leaks, corrosion, or other conditions that could
lead to a discharge as described in Sec.  112.1(b) is intended to
increase the likelihood that a discharge will be prevented or detected
promptly. This is especially true for components that typically cause
discharges, such as dump valves. These requirements are consistent with
the inspection requirements for bulk storage containers under Sec.
112.9(c)(3). EPA recognizes that because oil production facilities are
typically unattended, remote, and have a constant flow of oil and well
fluids, sized secondary containment measures provide environmental
protection for any potential discharge. EPA does not intend for
inspections to create a public safety concern for personnel conducting
inspections and EPA expects that the SPCC Plan will include provisions
to address weather-related concerns that may impact the inspection
schedule. Because EPA is revising the rule such that flow-through
process vessels are subject to the general secondary containment
requirement (Sec.  112.7(c)) instead of the sized secondary containment
requirement, the Agency seeks to ensure that any leak, or potential for
a leak, is detected promptly enough to prevent a discharge of the
entire contents of the separation or treating equipment. Therefore, EPA
believes it is important to require that inspections be completed and
documented in accordance with the requirements in Sec.  112.7(e).
    EPA is amending the requirement under Sec.  112.9(c)(5)(iii) with
some modifications to the proposed language, in response to comments
regarding removal of oil accumulations. Specifically, commenters
suggested adding language that would acknowledge that other methods of
immobilizing hydrocarbons in solid matrices, such as physical, chemical
and/or biological treatment methods should be allowed. EPA agrees that
other methods may be used to stabilize and remediate and thus, the
Agency is adding the phrase, ``remove or initiate actions to stabilize
and remediate'' to address this concern. EPA considers the removal of
oil-contaminated soil as a method to prevent oil from becoming a
discharge as described in Sec.  112.1(b). Disposal of oil must be in
accordance with applicable Federal, state, and local requirements;
under Sec.  112.7(a)(3)(v), a facility owner or operator is required to
describe the methods of disposal of recovered materials in accordance
with applicable legal requirements. For the purposes of this provision,
removal of recoverable oil may be combined with physical, chemical,
and/or biological treatment methods to address any residual oil. These
treatment methods must be consistent with other Federal, state or local
requirements as applicable, and must be properly managed to prevent a
discharge as described in Sec.  112.1(b). However, the Agency disagrees
with the comment that suggested replacing ``Promptly remove'' with
``Upon discovery.'' ``Promptly remove'' indicates that the owner or
operator of a facility has both the responsibility and flexibility to
outline an inspection program under Sec.  112.9(c)(5)(i) which puts the
timeframe for ``prompt removal'' in the context of the inspection
frequency.
    Finally, EPA believes that variations in oil production facility
piping design, layout, and location make flexibility important in order
to encourage compliance with these additional measures. However, such
flexibility is already available in that these requirements for flow-
through process vessels are subject to the environmental equivalence
provision found at Sec.  112.7(a)(2). For example, other Federal or
state requirements may be environmentally equivalent to certain SPCC
requirements. Thus, the facility owner or operator may deviate from the
requirements if an environmentally equivalent alternate measure,
subject to review and certification by a PE, is implemented. The
environmental equivalence provision found at Sec.  112.7(a)(2) cannot
be used for any containment provision associated with flow-through
process vessels.
c. Reportable Discharge
    EPA is finalizing a provision at Sec.  112.9(c)(5)(iv) to require
that a production facility owner or operator ensure that all flow-
through process vessels subject to this subpart (that is, are using the
new alternative to sized secondary containment) comply with Sec.
112.9(c)(2) and (c)(3) within six months from the discovery of a
discharge from a flow-through process vessel of more than 1,000 U.S.
gallons of oil in a single discharge as described in Sec.  112.1(b), or
more than 42 U.S. gallons of oil in each of two discharges as described
in Sec.  112.1(b), occurring within any twelve month period. When
determining spill history, the amount specified in the criterion
(either 1,000 or 42 U.S. gallons) refers to the amount of the discharge
that actually reaches navigable waters or adjoining shorelines, and not
the total amount of the discharge. Discharges as described in Sec.
112.1(b) that are the result of natural disasters, acts of war, or
terrorism are not considered toward this requirement. A flow-through
process vessel using this alternative approach must already comply with
Sec.  112.9(c)(1) and Sec.  112.9(c)(4) and therefore these
requirements were not added to Sec.  112.9(c)(5)(iv).
    Comments. Two commenters expressed concern with the reportable
discharge criterion because Sec.  112.4 already requires a facility
with a discharge as described in this provision to submit a report to
the Regional Administrator within 60 days.
    Response to comments. While the Agency acknowledges that EPA
continues to require a facility that has had a discharge as described
in Sec.  112.1(b) to submit a report to the Regional Administrator
within 60 days, EPA believes that the owner or operator of a facility
that has had such a discharge, as described in this criterion, should
be required to comply with the sized secondary containment requirement
because it would appear that the facility was not able to prevent
discharges to navigable waters or adjoining shorelines by complying
with the alternative standard--that is, general

secondary containment with additional measures. If a facility owner or
operator is unable to successfully prevent oil discharges using general
containment requirements and additional measures, EPA believes that
requiring sized secondary containment provides a fail-safe method to
address the risk of discharges. The Agency's preferred method for
preventing discharges from flow-through process vessels at these
constantly-flowing, unattended facilities is the use of sized secondary
containment. Sized secondary containment provides a buffer to allow for
containment of fluids from these vessels until a discharge is
discovered. Thus, the owner or operator would be required to
automatically amend the SPCC Plan and provide sized secondary
containment for all flow-through process vessels at the production
facility within six months of the discharge. This containment must be
sized to contain the contents of the single largest container, with
sufficient freeboard for precipitation. Additionally, the owner or
operator must submit a report to the EPA Regional Administrator as
required under Sec.  112.4(a).
    The discharge criterion is a well-established threshold in the SPCC
rule. This discharge criterion is similar to the provision in Sec.
112.4(a) for discharges that must be reported to the EPA Regional
Administrator. Under Sec.  112.4, a facility owner or operator must
report certain information to the Regional Administrator whenever the
facility experiences a discharge reportable under Sec.  112.4. The
Agency has used this criterion for eligibility for alternative measures
in the past, such as to allow the owner or operator of a qualified
facility to self-certify the SPCC Plan and to allow the use of
contingency planning and other measures in lieu of secondary
containment for qualified oil-filled operational equipment (see 71 FR
77266, December 26, 2006). The Agency believes that finalizing this
criterion to trigger the requirement to redesign secondary containment
is consistent with other spill history criteria used elsewhere in the
SPCC rule.
6. Alternative Qualified Facility Eligibility Criteria for Oil
Production Facilities
    In December 2006 (71 FR 77266, December 26, 2006), EPA promulgated
an amendment to the SPCC rule to allow the owner or operator of a
qualified facility to self-certify his SPCC Plan, which in this final
rule EPA identifies as a Tier II qualified facility. Furthermore, as
described in Section V.G of this notice, EPA is establishing an
additional option for a subset of qualified facilities (designated as
Tier I qualified facilities) that meet an additional criterion. The
owner and operator of a Tier I qualified facility may complete and
implement a streamlined, self-certified SPCC Plan template (promulgated
as Appendix G to 40 CFR part 112).
    The following table illustrates the tiers, criteria, and options
for production facilities meeting the qualified facilities eligibility
criteria and all other production facilities, as described in this
notice:

------------------------------------------------------------------------
     Production facilities that are qualified
                    facilities                      All other production
---------------------------------------------------      facilities
           Tier I                    Tier II
------------------------------------------------------------------------
Oil production facility and:                        Oil production
(1) No more than two producing wells per single      facility with an
 tank battery / ten barrels or less of crude oil     aggregate
 per well per day / if the facility has an           aboveground oil
 injection well; or                                  storage capacity
(2) No more than four producing wells per single     greater than 10,000
 tank battery / ten barrels or less of crude oil     gallons and:
 per well per day / no injection wells; or          (1) More than two
(3) The facility has10,000 U.S. gallons or less      producing wells per
 aggregate aboveground oil storage capacity; and     single tank battery
                                                     with one or more
                                                     injection wells;
                                                    (2) More than four
                                                     producing wells per
                                                     single tank
                                                     battery; or
                                                    (3) More than ten
                                                     barrels of crude
                                                     oil produced per
                                                     well per day; or
------------------------------------------------------------------------
Within any twelve-month period, three years prior   Within any twelve-
 to the Plan certification date, or since becoming   month period, three
 subject to the SPCC rule if in operation for less   years prior to the
 than three years, there has been:                   Plan certification
(1) No single discharge of oil to navigable waters   date, or since
 or adjoining shorelines exceeding 1,000 U.S.        becoming subject to
 gallons; and                                        the SPCC rule if in
(2) No two discharges of oil to navigable waters     operation for less
 or adjoining shorelines each exceeding 42 U.S.      than three years,
 gallons*; and                                       there has been:
                                                    (1) A single
                                                     discharge of oil to
                                                     navigable waters or
                                                     adjoining
                                                     shorelines
                                                     exceeding 1,000
                                                     U.S. gallons; or
                                                    (2) Two discharges
                                                     of oil to navigable
                                                     waters or adjoining
                                                     shorelines each
                                                     exceeding 42 U.S.
                                                     gallons*; or
------------------------------------------------------------------------
No individual aboveground     Has individual        Owner or operator
 oil containers greater than   aboveground oil       eligible for
 5,000 U.S. gallons;           containers greater    qualified facility
                               than 5,000 U.S.       status, but decides
                               gallons; or           not to take the
                              Owner or operator      option;
                               eligible for Tier I
                               qualified facility
                               status, but decides
                               not to take the
                               option or chooses
                               to develop a
                               ``hybrid'' Plan;.
------------------------------------------------------------------------
Then: Complete and self-      Then: Prepare a self- Then: Prepare a PE-
 certify Plan template         certified Plan in     certified Plan in
 Appendix G to 40 CFR part     accordance with all   accordance with all
 112) in lieu of a full PE-    applicable            applicable
 certified Plan.               requirements of       requirements of
                               Sec.   112.7 and      Sec.   112.7 and
                               subparts B and C of   subparts B and C.
                               the rule, in lieu
                               of a PE-certified
                               Plan.
------------------------------------------------------------------------
* This criterion does not include discharges as described in Sec.
  112.1(b) that are the result of natural disasters, acts of war, or
  terrorism. Additionally, the gallon amount described in this criterion
  addresses the amount of the discharge that actually reaches navigable
  waters or adjoining shorelines.

    In the October 2007 proposed rule, EPA solicited comment on whether
the Agency should consider alternative criteria in identifying a
``qualified facility,'' and thus, allow the owner or operator of an oil
production facility to self-certify the SPCC Plan, notwithstanding the
tank storage capacity at the facility. Specifically, EPA requested
comment on an approach that was suggested by EPA and two approaches
that were suggested by DOE (see 72 FR 58411, October 15, 2007 for a
more detailed description of the specific approaches on which EPA
solicited comment.) Based on the comments received, and the Agency's
evaluation of this industry sector, EPA is finalizing in this rule an
amendment that provides alternative criteria for identifying qualified
facilities in the oil production sector for onshore facilities. EPA
believes that alternative eligibility criteria for identifying a
qualified facility for certain onshore oil production facilities is
appropriate because, notwithstanding their simple configurations, many
of these small oil production facilities cannot meet the 10,000 gallon
aggregate aboveground oil storage capacity threshold for Tier I and II
qualified facility designation. Given (1) the large number of marginal
or stripper wells in the U.S.\6\; (2) that they contribute a
significant portion of the country's oil production; and (3) EPA's
understanding of the particular aboveground oil storage container
capacities and the nature of the fluids handled at certain small oil
production facilities, other criteria beyond oil storage container
capacity are more appropriate in determining whether an owner or
operator of such a facility should self-certify his SPCC Plan. These
other criteria, unique to small oil production facilities, serve to
identify a qualified facility consistent with the intent of this
approach as promulgated on December 26, 2006 (71 FR 77266), by
identifying the simplest operations by factors other than strictly
capacity.
---------------------------------------------------------------------------

    \6\ The Interstate Oil and Gas Compact Commission estimates that
there are 422,255 marginal oil wells as of January 1, 2007 (IOGCC
Marginal Wells: 2007 Report).
---------------------------------------------------------------------------

    A qualified oil production facility is one that meets all of these
conditions: (1) No more than two producing wells per single tank
battery if the facility has an injection well; or no more than four
producing wells per single tank battery with no injection wells at the
facility; (2) each well produces no more than ten barrels of crude oil
per day; and (3) the facility has not had a single discharge as
described in Sec.  112.1(b) exceeding 1,000 U.S. gallons or two
discharges as described in Sec.  112.1(b) each exceeding 42 U.S.
gallons within any twelve month period in the three years prior to Plan
certification, or since becoming subject to 40 CFR part 112 if the
facility has been in operation for less than three years. Facilities
with no more than two producing wells are eligible to be a qualified
facility regardless of whether they have injection wells. Discharges as
described in Sec.  112.1(b) that are the result of natural disasters,
acts of war, or terrorism do not disqualify a facility owner or
operator from the alternative option described above.
    The Tier II qualified facility eligibility criteria at Sec.
112.3(g)(2) have been amended to include these criteria for oil
production facilities. The owner or operator of a qualified oil
production facility may choose to prepare a self-certified SPCC Plan in
lieu of a Plan certified by a PE. An oil production facility owner or
operator exercising this option may be required to make production or
shipping records available to support his eligibility. Records kept
under usual and customary business practices will suffice, and must be
kept for a period of three years, in accordance with Sec.  112.7(e).
    Owners or operators of oil production facilities may meet Tier II
qualified facility eligibility through either criterion--has an
aggregate aboveground oil storage capacity of 10,000 U.S. gallons or
less (Sec.  112.3(g)(2)(i)); or the criteria described above for an
onshore oil production facility (Sec.  112.3(g)(2)(ii)). An oil
production facility that also meets the Tier I qualified facility
eligibility criteria in Sec.  112.3(g)(1) (that is, the facility has no
individual oil storage container with a capacity greater than 5,000
U.S. gallons) would be eligible to develop an SPCC Plan following the
template in Appendix G to the SPCC rule finalized in this rulemaking
(see Section V.G of this notice).
    Elsewhere in today's preamble, EPA clarified that a natural gas
production facility storing condensate (petroleum oil), in quantities
that meet the SPCC applicability criteria, is considered an oil
production facility. Since such an onshore natural gas production
facility, as described above, is considered an onshore oil production
facility, it may be eligible for the qualified facility relief for
marginal wells if it meets the other new criteria finalized today in
Sec.  112.3(g)(2)(ii). Additionally, since a natural gas production
facility can often store smaller quantities of oil, the facility may
already meet the existing ``capacity based'' qualified facility
criteria in Sec.  112.3(g)(2)(i), available to all facility types.
    Additionally, in order to provide the owner or operator of a
production facility that meets the qualified facility criteria with the
necessary time to fully understand the new regulatory options finalized
in today's action, EPA is proposing, in a separate action in the
Federal Register of November 26, 2008 (73 FR 72016), a new compliance
date to prepare or amend and implement the production facility's SPCC
Plan.
a. Alternative Qualified Facility Eligibility Criteria for Oil
Production Facilities
    This approach is intended as an alternative to the existing 10,000
gallon aggregate aboveground oil storage capacity eligibility criteria.
It provides tailored qualified facility eligibility criteria based on
process operating conditions and equipment unique to oil production
facilities rather than static oil storage capacity. The owner or
operator of an oil production facility that meets the 10,000 gallon
threshold may already self-certify his SPCC Plan and does not also need
to meet the differentiated criterion for oil production facilities
finalized in this action.
    Ten barrels or less of crude oil produced per well per day. The ten
barrels or less per well per day criteria was chosen because this
production rate is consistent with the definition of a ``stripper
well.'' EPA established differentiated requirements for ``stripper
wells'' under the CWA, which were codified in 1979 (see 40 CFR 435.60).
The Interstate Oil and Gas Compact Commission (IOGCC) also defines
``stripper wells'' as wells that produce ten barrels of oil per day or
less.\7\ This production rate limits the qualified oil production
facility approach to those facilities with smaller quantities of oil
and associated fluids.
---------------------------------------------------------------------------

    \7\ See Interstate Oil and Gas Compact Commission, 2006:
``Marginal Wells: Fuels for Economic Growth'', p. 4 (defining
``stripper wells'' as wells that produce 10 barrels of oil per day
or less).
---------------------------------------------------------------------------

    Maximum of two producing wells per single tank battery (if the
facility has an injection well) or maximum of four producing wells per
single tank battery (with no injection wells at facility). In the
October 2007 proposal, EPA suggested that the criterion used to
identify qualified oil production facilities should be a maximum of
four wells at a single tank battery producing no more than ten barrels
of oil per day (72 FR 58378, October 15, 2007). The Agency requested
comment on this approach. While commenters expressed

support generally for a definition of ``qualified facility'' specific
to the oil production sector, they also argued that limiting the
definition to those facilities with four wells or fewer would not allow
many facilities to take advantage of this approach. However, the Agency
analyzed comments provided on the original proposal that established
qualified facilities (70 FR 73524, December 12, 2005) together with the
comments provided on the approach described in the October 2007
proposed rule (72 FR 58378) relative to the overall reason for
identification of a qualified facility; that is, that owners and
operators of facilities that handle small oil quantities, with simple,
straightforward processes and equipment, should be capable of
developing, implementing, and self-certifying an SPCC Plan without the
services of a PE. With this underlying principle in mind, EPA
considered the type and scale of operations and the equipment involved
at small, marginal well oil production facilities and concluded that
when there are no injection wells at the facility, four producing wells
per single tank battery is an appropriate criteria to define a simple
oil production facility configuration.
    One or more injection wells are typically used to inject produced
water underground for disposal or to enhance recovery of oil from
production wells. The underground injection process can add additional
piping to the design of an oil production facility. Consequently, EPA
has included a ``no injection wells'' criterion for qualified oil
production facilities with more than two wells per single tank battery.
The injection well process typically consists of piping extending from
a produced water container to the injection wellhead, valves, and pumps
and may include tank level indicators, floats, flow controls, and
actuators/switches that add additional equipment to the oil production
facility. EPA believes the integration of such injection equipment and
its operation into the design and operation of the production facility
calls for PE certification rather than the owner or operator self-
certifying of the SPCC Plan at facilities that have more than two
production wells and injection wells. EPA also does not believe it is
reasonable or appropriate for an owner or operator to designate the
injection well and its associated piping a separate facility just to
meet the alternative qualified facility eligibility criteria. However,
as noted in section V.M.7, an injection well that injects fluids that
were stored in a container that is exempt from the SPCC regulation
under Sec.  112.9(c)(6)(i) will not preclude a facility from being
eligible for treatment as a qualified facility under Sec.
112.3(g)(2)(ii). Therefore, the Agency believes that at a facility with
no injection wells and a maximum of four producing wells per single
tank battery, each of which produce ten barrels or less of crude oil
per well per day, captures the oil production operations targeted by
the self-certification option because these facilities, with a limited
number of producing wells per tank battery operating at a low flow
rate, and no injection wells or associated equipment, are less complex
than other oil production facilities.
    Commenters also argued that ``no injection wells'' is not part of
an established definition and that small facilities that utilize
injection for secondary or tertiary recovery would not qualify. As EPA
considered the type and scale of operations, and the likely quantities
of oil handled, EPA also analyzed whether marginal well oil production
facilities with an injection well that handle small oil quantities
could be similarly less complex than other oil production facilities.
The Agency established the threshold of two wells per single tank
battery if there is one or more injection wells at the facility because
field observation and professional judgment suggests that with two
wells, the tank battery is typically situated near the well head to
minimize the length of flowlines. As the number of wells flowing to a
single tank battery decreases to two wells, the footprint of the
facility potentially decreases and the lesser area encompassed by a
facility with fewer wells flowing to the tank battery means that
significantly shorter flowlines are needed to move well fluids to
separation and storage processes. EPA also understands that as the
number of wells in a lease (the term used for the area of wells run by
an owner or operator) decreases, the number of tanks and separators
typically decreases. Depending on the flow rates and well locations,
separate tank batteries serving widely separated wells may be installed
on one lease. Fewer valves, smaller separation equipment and fewer or
smaller storage tanks in the tank battery are also expected at a
facility with two wells than those with four wells per single tank
battery. Finally, based on the Agency's best professional judgment and
experience in the field, pumpers and well service operations typically
occur once or twice per week; on this basis, the likely quantities of
well fluids and marketable oil generated by a two-well operation per
single tank battery is more consistent with the quantities expected at
qualified facilities that are not oil production facilities. By
limiting the overall number of producing wells, and therefore the
associated equipment and piping at an oil production facility, the
Agency is targeting those production facilities that should be eligible
to self-certify SPCC Plans. In order to strike a balance between those
operations with injection wells and those without, EPA is allowing oil
production facilities with no more than two producing wells that also
have injection wells an option to self certify the Plan. Regardless of
the presence of injection wells at these facilities, the overall number
of wells and associated equipment is still limited by this approach. In
addition, the likely smaller oil quantities stored at a two-well
facility with injection wells captures the smaller operators targeted
by the self-certification option because these facilities are similar
in complexity to an oil production facility with four producing wells
per tank battery with no injection wells. Similarly, the specification
of ``per single tank battery'' is intended to make clear that the self-
certification option for production facilities does not extend to a
central processing area (a production treatment and separation
operation that receives fluids from a qualified facility tank battery).
    Although the criterion limits the number of wells per single tank
battery, it does not limit the number of tank batteries located at the
oil production facility. That is, EPA believes that tank batteries
within an oil production facility may still have simple configurations
and the presence of multiple tank batteries does not add complexity to
the overall oil production facility. As EPA discussed previously in
Section V.D of the preamble, the owner or operator of a production
facility has the flexibility to define the facility's boundaries such
that it can include multiple tank batteries. Therefore, if the oil
production facility meets one of the two alternative criteria described
in this section (that is, it has no more than two producing wells per
single tank battery each of which produce ten barrels or less of crude
oil per well per day if there are injection wells; or the facility has
no more than four producing wells per single tank battery, each of
which produce ten barrels or less of crude oil per well per day, and
has no injection wells at the facility; and meets the reportable
discharge history criterion) the owner or operator can self-certify the
SPCC Plan.
    Comments. Many commenters expressed general support that EPA

utilize other relevant criteria in identifying a ``qualified facility''
in the oil production sector, although most of the commenters did not
support the approach EPA is promulgating in this final rule. However,
other commenters questioned why oil production facilities would have
different criteria than facilities in other industries when they
already have less stringent requirements under the SPCC rule. Two
commenters opposed any alternative eligibility criteria for production
facilities, arguing that the basis of the qualified facility approach
is to provide an alternative for the truly small operator to avoid the
cost of PE certification of his SPCC Plan. Commenters questioned why
EPA would reduce requirements for oil production facilities given the
sector's spill history and operational complexity. These commenters
requested that all facilities above 1,320 gallons of total aboveground
oil storage capacity should be certified by a PE.
    Still other commenters questioned the number of wells and other
conditions that EPA described in the preamble to the proposal. One
commenter stated that limiting the option to facilities with four wells
is of concern because the number is not well-established and would
restrict the applicability of this option. Several commenters also
expressed concern with the ``no injection wells'' criterion, noting
that injection does not add complexity to the facility, is a common
practice, and the produced water that is reinjected is of low oil
content. Commenters also stated that ``no injection wells'' is not part
of an established definition and that small facilities that utilize
injection for secondary or tertiary recovery would not qualify.
    Other commenters suggested other approaches or options that EPA
could pursue. For example, one commenter suggested the alternative
eligibility criteria should be a production rate less than five barrels
per day per well, and very simple operations consisting of no more than
three wells flowing to one tank battery and no injection wells. Two
other commenters provided support for oil production facilities to
qualify for Tier I, although some commenters suggested that the Tier I
qualified facility threshold discussed in the October 2007 proposal
would be too limiting, and suggested that a facility with one 400
barrel (16,800 U.S. gallons) oil tank should be eligible for the Tier I
category.
    Response to comments. EPA agrees in principle with the commenters
who supported alternative qualified facility eligibility criteria for
oil production facilities and is finalizing the option described in the
proposal with some modifications. The Agency does not agree that PE
certification should be required for all facilities with more than
1,320 U.S. gallons oil storage capacity, given that the Agency has
already promulgated an approach allowing owners and operators of
facilities that meet certain criteria, including a total aboveground
oil storage capacity of 10,000 U.S. gallons or less to self-certify
Plans. A number of commenters pointed out that oil production
facilities are already subject to a differentiated set of requirements
under the SPCC rule. While the Agency recognizes this, it continues to
believe that a differentiated alternative for facilities with simple
configurations has merit, and that providing the added flexibility of
self-certification for the smaller oil handlers/simpler operations,
along with the other streamlined requirements tailored to the unique
features of this sector (as described elsewhere in the preamble to this
final rule) should improve overall spill prevention and environmental
protection.
    Because the configuration of an oil production facility is
variable, complexity depends upon a number of factors, including, but
not limited to: The oil field, production rate, type of fluid,
operating equipment and conditions, and viscosity of the oil. Because
oil production facilities do not have a ``typical'' configuration, the
Agency has finalized eligibility criteria intended to minimize the
complexity of the operations where self-certification seems
appropriate. By setting the maximum number of wells at four producing
wells if there are no injection wells at the facility, or two producing
wells if there are injection wells at the facility, there is a greater
likelihood that those wells are located near the tank battery. EPA
believes that the four-well criterion targets those oil production
facilities with less complex operations and configurations, consistent
with other qualified facilities. Similarly, the criterion that excludes
underground injection for a facility with four producing wells
eliminates the complexity associated with injection related equipment.
By limiting the number of producing wells per single tank battery to
two producing wells at facilities that have injection, EPA believes
that because of the smaller oil storage capacities and the greater
likelihood that those wells are located near the tank battery, a
marginal well oil production facility with two producing wells is
consistent with other qualified facilities. In addition, the reduced
complexity in decreasing from four to two producing wells is similar to
the change in complexity associated with injection wells. As noted
above, EPA believes a PE need not be involved in the SPCC Plan at
facilities with a limited number of wells and associated equipment and
piping.
    A number of commenters noted that by limiting the number of wells
per tank battery and not allowing injection wells to be utilized in
designating a qualified facility for the oil production sector, it
would limit the number of oil production facilities that could self-
certify their SPCC Plan. First, it should be noted that in designating
a ``qualified facility'' in the oil production sector, the purpose is
to identify those facilities that should be eligible to self-certify
their SPCC Plan without the involvement of a PE-that is, those
facilities that handle small quantities of oil, with simple and
straightforward processes and equipment, and not to maximize the number
of oil production facilities that could be eligible to self-certify
their SPCC Plan. However, EPA also estimated the number of facilities
that would meet the eligibility criteria for a qualified facility under
the eligibility criteria promulgated today for the oil production
sector. Based on our analysis (which can be found in the Regulatory
Impact Analysis for this action, located in the docket for this
rulemaking), EPA estimates that approximately one third of oil
production facilities would meet the alternative eligibility criteria.
If those oil production facilities that meet the eligibility criteria
for self-certification based on the 10,000 gallon threshold are also
included, EPA estimates that almost half of oil production facilities
could take advantage of self-certifying their SPCC Plan. Thus, EPA does
not agree with commenters that the eligibility criteria being
promulgated today for defining a qualified facility in the oil
production sector is too narrow.
    The Agency also agrees that oil production facilities should also
be eligible as Tier I qualified facilities. Thus, the owner or operator
of an oil production facility that meets the criteria finalized under
this rulemaking and additionally meets the Tier I qualified facility
eligibility criteria in Sec.  112.3(g)(1) (that is, the facility has no
individual oil storage container with a capacity greater than 5,000
U.S. gallons) is also eligible to use the streamlined Tier I qualified
facility SPCC Plan template (Appendix G to the SPCC rule). The Agency
also does not agree that the eligibility criteria for Tier I are too
limiting, as the relief provided by the SPCC Plan template and other
streamlined requirements are targeted to

a specific segment of the universe of facilities based upon simplicity
of configuration and a 5,000-gallon limit on the total aboveground
storage capacity for any single container. EPA believes that facilities
that qualify for Tier I have a reduced risk of discharge in harmful
quantities due to this limit on aboveground single container total
storage capacity. Thus, the Agency does not agree that a 400-barrel
container (16,800 U.S. gallons) should qualify for Tier I, as this
quantity is three times the container threshold for other Tier I
qualified facilities (with a maximum aboveground oil storage container
of 5,000 U.S. gallons). Commenters did not provide data to support the
larger tank size or demonstrate how this would maintain environmental
protection. Larger containers have the potential for a larger
discharge, may have more stringent requirements for inspection and
maintenance in accordance with industry standards, and therefore, EPA
believes should not be eligible for the Tier I streamlined
requirements.
b. Alternative Approaches for Addressing Small Oil Production
Facilities as Suggested by the Department of Energy (DOE): Alternative
Eligibility Criteria
    In the proposal to this rulemaking (72 FR 58378, October 15, 2007),
the Agency sought input on different eligibility criteria, as suggested
by DOE, to identify a small oil production facility as a qualified
facility. The criteria would allow for the development of a self-
certified SPCC Plan, and allow the use of a streamlined SPCC Plan
template for a certain set of facilities, similar to that found in
proposed Appendix G to the SPCC rule. Under the qualified facility
criteria at Sec.  112.3(g), a facility that has an aggregate
aboveground oil storage capacity of 10,000 U.S. gallons or less and has
not had a single discharge as described in Sec.  112.1(b) exceeding
1,000 U.S. gallons or two discharges as described in Sec.  112.1(b)
each exceeding 42 U.S. gallons within any twelve-month period in the
three years prior to Plan certification, or since becoming subject to
40 CFR part 112 if the facility has been in operation for less than
three years is eligible for the qualified facility Plan requirements at
Sec.  112.6 (i.e., a self-certified Plan in lieu of a PE certified
Plan). DOE suggested that because of the unique characteristics of
small oil production facility operations, such facilities may merit the
establishment of small oil production facility-specific eligibility
criteria, including a different aggregate oil storage capacity
threshold or stripper well definition for identifying qualified
facilities. For example, DOE suggested that a stripper well be defined
using the IRS tax code definition of 15 barrels or less of oil per day
equivalence (see 26 U.S.C. 613A). In light of this request, EPA sought
comment on whether there are unique circumstances at small or
marginally economic oil production facilities and the alternative
criteria based on these circumstances for the possible establishment of
a ``qualified facility'' provision specific to small oil production
facilities that would serve to increase SPCC spill prevention and
reduce the likelihood of a harmful oil discharge.
    Comments. Several commenters argued that the current threshold
requirements are too low to provide significant benefit for marginal
oil production facilities. For example, one commenter suggested a total
aboveground oil storage capacity of 50,000 gallons where no single
container is greater than 21,000 gallons, whereas another commenter
suggested removing consideration of this approach unless produced water
storage is eliminated from the threshold calculation.
    Concerning the stripper well definition, two commenters supported
DOE's suggestion to use the IRS tax code definition for marginal
production to ease compliance. One commenter indicated that the EPA
definition remains linked to facility storage capacity, and storage
capacity at marginal wells is not sized based on current production
levels and in fact decreases over time.
    Concerning other regulatory programs addressing the objectives of
the SPCC rule, one commenter suggested that state spill prevention
regulatory programs should serve small production facilities rather
than one Federal program. However, another commenter noted that states
in general simply do not address equivalent requirements of the SPCC
regulations and especially not to the extent of the SPCC regulations
with respect to prevention of oil discharges. Two commenters suggested
that EPA consider other regulatory requirements, including DOT Carrier
Requirements for Spills, Spill Reporting, Transportation Security
Planning, and EPA's Stormwater Discharge Permitting program, the
National Pollutant Discharge and Elimination System (NPDES) program,
and Underground Injection Control (UIC) program. Another commenter
suggested allowing all SPCC facilities to have the option of using
other equivalent prevention plans to meet SPCC planning requirements.
Finally, one commenter suggested that EPA remove the self-certification
provision from the rules so that all farmers, small businesses and
other oil storage facilities are required to prepare a complete SPCC
Plan certified by a PE to ensure ``equal and fair treatment for all
owners and operators.''
    Response to comments. The Agency disagrees with commenters who
suggest establishing a new capacity based Tier II criterion for oil
production facilities greater than the already established 10,000-
gallon threshold for all facilities. While the Agency received a number
of comments regarding a wide variety of thresholds for defining a Tier
II qualified facility in the oil production sector, the comments did
not provide sufficient data to support the threshold numbers other than
it would increase the number of facilities that would be eligible as a
qualified facility and thus, self-certify their SPCC Plan. More
importantly, the commenters did not demonstrate how these new
thresholds would maintain environmental protection. EPA does not agree
with the commenters to base a new Tier II qualified facility threshold
for oil production operations solely on an increased capacity
threshold, as there was no justification for providing oil production
facilities with a higher threshold than non-production facilities or
for how the higher threshold relates to simplicity in facility
configuration or operations.
    Nevertheless, EPA agrees with commenters that the oil production
sector has unique characteristics and that other criteria may better
serve in defining a Tier II qualified facility. For example, the fact
that oil production facilities have flow-through process vessels
suggests that flow rate (in the form of an oil production rate) may be
a better approach for setting a new criterion for identifying the
simplest oil production facility operations. However, EPA disagrees
with commenters who argued that the IRS tax code definition of 15
barrels or less of oil per day should be used in defining flow rate.
Specifically, the IRS definition of 15 barrels of oil or less per day
equivalent is calculated by dividing the average daily production of
domestic crude oil and domestic natural gas from producing wells on
such property for such calendar year by the number of such wells. Thus,
under this approach, a facility will contain wells with marginal
production, such as 15 barrels of oil per day, but also will likely
contain wells that produce much greater quantities of oil, because the
IRS definition calculates the average daily production of oil over all
producing wells, as opposed to the amount of oil

that flows from any individual well. EPA believes that using such a
definition defeats the purpose of identifying a qualified facility,
which is to allow those small facilities that have relatively simple
operations to self-certify their SPCC Plans. Thus, the Agency has
adopted a per well approach that places a flow rate cap of ten barrels
or less of oil produced per well per day, as this is consistent with
the definition of ``stripper well'' codified at 40 CFR 435.60.
    Additionally, because the source of the oil for production
facilities is through extraction wells, the number of wells better
identifies the complexity of a production operation. Finally, some of
these facilities are unique as they reinject fluids in the reservoir
for disposal purposes or for enhanced oil recovery. The presence of
these injection wells is a characteristic unique to oil production
facilities that can help to determine the complexity of the operation.
These characteristics, unique to the oil production sector, provided
the Agency with the basis for a tailored set of criteria to identify
oil production facilities with simple configurations. Developing a
criterion based solely on raising the oil storage capacity criterion
would be inconsistent with the rationale established for the original
10,000-gallon criterion and would not necessarily maintain
environmental protection. Thus, while EPA does not agree that raising
the oil storage capacity threshold is appropriate, the Agency does
agree with commenters that the unique characteristics of an oil
production facility allow EPA to establish alternative criteria for a
Tier II qualified facility, and EPA has finalized provisions to that
effect.
    Finally, EPA disagrees with commenters who suggested that the SPCC
regulations are not needed because of other regulatory programs, such
as state programs, or the NPDES or UIC programs. EPA conducted a
comparison of a number of these programs with the SPCC program and
found that they were not nationally uniform (see Review of State
Regulations Pertaining to Oil Spill Prevention at Onshore Production
Facilities and Produced Water Containers, prepared by Abt Associates
Inc., June 6, 2008, and found in the docket for today's rulemaking).
Further, under the Oil Pollution Act and CWA, EPA is required to
promulgate oil spill prevention regulations, and it cannot delegate its
responsibilities to other Federal or state programs, but has
streamlined SPCC requirements or provided targeted exemptions from SPCC
regulation when such regulations provide comparable or equivalent
environmental protection. However, EPA has stated previously that if a
facility owner or operator must comply with a state or Federal
requirement that also satisfies an SPCC requirement, the owner or
operator can include and reflect such effort in his SPCC Plan and not
duplicate it solely for SPCC. EPA wants to minimize duplicative
requirements where possible and is working to tailor requirements,
where appropriate.
c. Alternative Approaches for Addressing Small Oil Production
Facilities as Suggested by the Department of Energy (DOE): Exempt
Existing Stripper Oil and Natural Gas Wells From all SPCC Requirements
    The other approach that DOE requested that EPA solicit comment on
in the proposal to this rulemaking (72 FR 58378, October 15, 2007) was
to exempt stripper oil and natural gas wells from all SPCC
requirements, except those applicable to crude oil and condensate tanks
(e.g., tanks which store gas condensate (which is an oil) at oil and
gas production facilities). The eligibility criteria for the exemption
would include those facilities that meet the IRS tax code definition of
stripper well property at 26 U.S.C. 613A. In addition, the eligibility
criteria would not be limited, for example, to those facilities that
did not have injection wells or used injection wells as secondary or
tertiary recovery techniques, which DOE has indicated may be regulated
under existing Federal and state regulatory programs. DOE believes that
such criteria have no direct relationship to the spill risk posed by
marginal wells facilities and may serve as a disincentive to enhanced
oil and gas recovery and well maintenance.
    Comments. Many of the commenters expressed support for an exemption
of stripper oil and natural gas wells from all SPCC requirements.
Commenters expressed concerns that implementation of the SPCC rule may
cause oil production wells to be shut in. One other commenter suggested
regulating only crude oil and condensate containers, given that the
releases reported to the NRC from this industry sector are low and EPA
``has never conducted a comprehensive environmental analysis of the
risks associated with these proposed regulations and whether they
significantly change from the current regulatory program to this
proposed one.''
    Response to comments. While the majority of comments the Agency
received supported an outright exemption for stripper oil and natural
gas wells from the SPCC requirements, the commenters did not provide
sufficient data to justify an exemption or demonstrate how an exemption
would maintain environmental protection. EPA also disagrees with the
commenters that the SPCC requirements and compliance costs alone would
cause small oil production facilities to shut down, reducing U.S. oil
production (see memorandum dated April 11, 2008, Preliminary Assessment
of SPCC Compliance Costs and Energy Impacts on Oil Exploration and
Production). As EPA has noted elsewhere, these facilities, which are
generally unattended, can store large quantities of oil and oil/water
mixtures in a variety of containers that may have large capacities.
These factors, as well as others, highlight the hazard potential posed
by these operations (see Considerations for the Regulation of Onshore
Oil Exploration and Production Facilities Under the Spill Prevention,
Control, and Countermeasures Regulation, May 30, 2007, in the docket
for this rulemaking (EPA-HQ-OPA-2007-0584-0015)). Thus, based on this
hazard, and without sufficient rationale, the Agency believes it
inappropriate to grant an outright exemption for such stripper oil and
natural gas wells from the SPCC requirements. However, EPA does agree
that performance-based requirements tailored to the unique
characteristics of marginal oil production facilities are justified, as
EPA has described previously, which the Agency believes will lead to
the prevention of oil spills.
7. Produced Water Containers
    In the proposal for this rulemaking (72 FR 58378, October 15,
2007), EPA requested comment including appropriate rationale,
information, and data, on three approaches related to produced water
containers. The first approach required general secondary containment
combined with additional requirements in lieu of sized secondary
containment. The second approach, advanced by DOE, required inspection,
maintenance, and periodic oil skimming of produced water containers in
lieu of both sized and general secondary containment. Finally, comment
was requested on a third approach, again advanced by DOE, that exempted
produced water treatment facilities altogether.
    Produced water containers are typically located within a tank
battery at

an oil production facility \8\ where they are used to store well fluids
that result after marketable crude oil is separated from fluids
extracted from the reservoir and prior to subsequent use (e.g., re-
injection or beneficial reuse), further treatment, or disposal. Under
normal operating conditions, a layer of oil may be present on top of
the fluids in these containers. The amount of oil by volume observed in
produced water containers varies, but based on EPA's understanding, is
generally estimated to range from less than one to up to ten percent,
and can be greater. However, the Department of Energy (DOE) and the oil
production sector indicate that the oil layer may be much less,
depending on the type of oil/water separation technology used, if any.
Many commenters claim that the SPCC oil spill prevention requirements
are inappropriately applied to produced water containers, arguing that
in certain cases these containers hold mostly water with very low
concentrations of oil or that produced water containers should be
exempt under the exemption for wastewater treatment. EPA agrees that
the SPCC regulations should not regulate the storage of oil if the
discharge of that oil is not prohibited under section 311 of the Clean
Water Act. Section 311(b)(3) prohibits the discharge of oil into or
upon navigable waters of the United States or adjoining shorelines in
such quantities as may be harmful, as determined by the President. That
determination is made in 40 CFR part 110. EPA does not agree that
produced water containers are eligible for the wastewater treatment
exemption. However, the Agency recognizes that, depending on the use,
some produced water containers may serve as oil/water separators,
rather than bulk storage tanks, and such containers should be regulated
in a similar fashion as other oil/water separators. To address these
concerns, EPA is providing an exemption for certain produced water
containers holding oil that would not violate section 311(b)(3) if
discharged, and a differentiated set of requirements for other produced
water containers at oil production facilities that are used for oil/
water separation. EPA is also promulgating a definition of produced
water container to clarify which containers will be eligible for this
rule amendment. The Agency believes that the approaches for produced
water containers promulgated in this rule amendment are a logical
outgrowth of the three approaches discussed in the proposal and the
comments received.
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    \8\ A wet gas facility that stores condensate and meets the
other SPCC qualifying criteria is considered an oil production
facility. Otherwise, a wet gas facility falls outside the scope of
the Agency's SPCC jurisdiction.
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    Specifically, EPA is finalizing two approaches for produced water
containers at oil production facilities. Under the first approach, EPA
is exempting produced water containers at oil production facilities
from the requirements of the SPCC rule when a PE certifies, as part of
the SPCC Plan, that based on the efficiency of the oil/water separation
technology used, the contents of a produced water container, if
completely discharged, does not contain oil in amounts that may be
harmful, as described in 40 CFR part 110; the capacity of the exempted
containers would not be counted in oil storage capacity.
    Under the second alternative, which is drawn from two of the
approaches presented in the proposal, for those produced water
containers that cannot meet the criterion for the exemption under this
rule, the facility owner/operator has the option to apply general
secondary containment requirements and conduct visual inspections,
maintenance and corrective action, in lieu of sized secondary
containment, when a PE describes in the Plan and certifies that a
practice is established that is designed to remove the amount of free-
phase oil from the produced water container on a scheduled and routine
basis. These containers are counted toward the aggregate storage