[Federal Register Volume 67, Number 137 (Wednesday, July 17, 2002)]
[Rules and Regulations]
[Pages 47042-47152]
From the Federal Register Online via the Government Publishing Office [www.gpo.gov]
[FR Doc No: 02-16852]



[[Page 47041]]

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Part II





Environmental Protection Agency





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40 CFR Part 112



Oil Pollution Prevention and Response; Non-Transportation-Related 
Onshore and Offshore Facilities; Final Rule

  Federal Register / Vol. 67, No. 137 / Wednesday, July 17, 2002 / 
Rules and Regulations  

[[Page 47042]]


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ENVIRONMENTAL PROTECTION AGENCY

40 CFR Part 112

[FRL-7241-5]
RIN 2050-AC62


Oil Pollution Prevention and Response; Non-Transportation-Related 
Onshore and Offshore Facilities

AGENCY: Environmental Protection Agency (EPA).

ACTION: Final rule.

-----------------------------------------------------------------------

SUMMARY: The Environmental Protection Agency (EPA or the Agency or we) 
is amending the Oil Pollution Prevention regulation promulgated under 
the authority of the Clean Water Act. This rule includes requirements 
for Spill Prevention, Control, and Countermeasure (SPCC) Plans, and for 
Facility Response Plans (FRPs). The final rule includes new subparts 
outlining the requirements for various classes of oil; revises the 
applicability of the regulation; amends the requirements for completing 
SPCC Plans; and makes other modifications. The final rule also contains 
a number of provisions designed to decrease regulatory burden on 
facility owners or operators subject to the rule, while preserving 
environmental protection. We expect that today's rule will reduce the 
paperwork burden associated with SPCC requirements by approximately 
40%. We have also made the regulation easier to understand and use.

DATES: This rule is effective August 16, 2002.

ADDRESSES: The official record for this rulemaking is located in the 
Superfund Docket at 1235 Jefferson Davis Highway, Crystal Gateway 1, 
Arlington, Virginia 22202, Suite 105. The docket numbers for the final 
rule are SPCC-1P, SPCC-2P, and SPCC-7. The record supporting this 
rulemaking is contained in the Superfund Docket and is available for 
inspection by appointment only, between the hours of 9 a.m. and 4 p.m., 
Monday through Friday, excluding legal holidays. You may make an 
appointment to review the docket by calling 703-603-9232. You may copy 
a maximum of 100 pages from any regulatory docket at no cost. If the 
number of pages exceeds 100, however, we will charge you $0.15 for each 
page after 100. The docket will mail copies of materials to you if you 
are outside of the Washington, DC metropolitan area.

FOR FURTHER INFORMATION CONTACT: Hugo Paul Fleischman, Oil Program 
Center, U.S. Environmental Protection Agency, at 703-603-8769 
([email protected]); or the RCRA/Superfund Hotline at 800-424-
9346 (in the Washington, DC metropolitan area, 703-412-
9810)([email protected]). The Telecommunications Device for the Deaf 
(TDD) Hotline number is 800-553-7672 (in the Washington, DC 
metropolitan area, 703-412-3323). You may wish to visit the Oil 
Program's Internet site at www.epa.gov/oilspill.

SUPPLEMENTARY INFORMATION: The contents of this preamble are as 
follows:

I. Entities Affected by This Rule
II. Introduction
    A. Statutory Authority
    B. Background of This Rulemaking
III. Summary of Major Rule Provisions
IV. Discussion of Issues
    A. Reorganization of the Rule
    B. Plain Language Format
    C. ``Should to Shall to Must'' Clarification
    D. Professional Engineers (PEs)
    1. State Registration
    2. PEs Employed by the Facility
    3. Completion of Testing
    4. Site Visits
    E. Electrical Facilities and Other Operational Users of Oil
    F. Discretionary Provisions
    G. Design Capabilities of Drainage Systems, Other than 
Production Facilities
    H. Compliance Costs
    I. Contingency Planning and Notification
    J. Reproposal
    K. Industry Standards
V. Section by Section Analysis (Includes: Background, Comments, and 
Response to Comments)
VI. Summary of Supporting Analyses
    A. Executive Order 12866--OMB Review
    B. Executive Order 12898--Environmental Justice
    C. Executive Order 13045--Children's Health
    D. Executive Order 13175--Consultation and Coordination with 
Indian Tribal Governments
    E. Executive Order 13132--Federalism
    F. Executive Order 13211--Energy Effects
    G. Regulatory Flexibility Act
    H. Unfunded Mandates Reform Act
    I. Paperwork Reduction Act
    J. National Technology Transfer and Advancement Act
    K. Congressional Review Act

I. Entities Affected by This Rule

    Entities Potentially Regulated by this Rule Include:

------------------------------------------------------------------------
              CATEGORY                            NAICS Codes
------------------------------------------------------------------------
Crop and Animal Production..........                            111-112.
Crude Petroleum and Natural Gas                                  211111.
 Extraction.........................
Coal Mining, Non-Metallic Mineral               2121/2123/213114/213116.
 Mining and Quarrying...............
Electric Power Generation,                                         2211.
 Transmission, and Distribution.....
Heavy Construction..................                                234.
Petroleum and Coal Products                                         324.
 Manufacturing......................
Other Manufacturing.................                              31-33.
Petroleum Bulk Stations and                                       42271.
 Terminals..........................
Gasoline Stations/Automotive Rental                           4471/5321.
 and Leasing........................
Heating Oil Dealers.................                             454311.
Transportation (including               482-486/488112-48819/4883/48849/
 Pipelines), Warehousing, and                             492-493/71393.
 Marinas............................
Elementary and Secondary Schools,                             6111-6113.
 Colleges...........................
Hospitals/Nursing and Residential                               622-623.
 Care Facilities....................
------------------------------------------------------------------------

    ``NAICS'' refers to the North American Industry Classification 
System, a method of classifying various facilities. The NAICS was 
adopted by the United States, Canada, and Mexico on January 1, 1997 to 
replace the Standard Industrial Classification (SIC) code. This table 
is not intended to be exhaustive, but rather provides a guide for 
readers regarding entities likely to be regulated by this action. It 
lists the types of entities of which we are now aware that could 
potentially be regulated by this action. Other types of entities not 
listed in the table could also be regulated. To determine whether your 
facility could be regulated by this action, you should carefully 
examine the criteria in Secs. 112.1 and 112.20 of title 40 of the Code 
of Federal Regulations and of today's rule, which explain the 
applicability of the rule. If you have questions regarding the 
applicability of this action to a particular entity, consult the person 
listed in the FOR FURTHER INFORMATION CONTACT section.

[[Page 47043]]

II. Introduction

A. Statutory Authority

    Section 311(j)(1)(C) of the Clean Water Act (CWA or Act), 33 U.S.C. 
1251, requires the President to issue regulations establishing 
procedures, methods, equipment, and other requirements to prevent 
discharges of oil from vessels and facilities and to contain such 
discharges. The President has delegated the authority to regulate non-
transportation-related onshore facilities under section 311(j)(1)(C) of 
the Act to the U.S. Environmental Protection Agency. Executive Order 
12777, section 2(b)(1), (56 FR 54757, October 22, 1991), superseding 
Executive Order 11735, 38 FR 21243. By this same Executive Order, the 
President has delegated similar authority over transportation-related 
onshore facilities, deepwater ports, and vessels to the U.S. Department 
of Transportation (DOT), and authority over other offshore facilities, 
including associated pipelines, to the U.S. Department of the Interior 
(DOI). A Memorandum of Understanding (MOU) among EPA, DOI, and DOT 
effective February 3, 1994, has redelegated the responsibility to 
regulate certain offshore facilities located in and along the Great 
Lakes, rivers, coastal wetlands, and the Gulf Coast barrier islands 
from DOI to EPA. See Executive Order 12777, section 2(i) regarding 
authority to redelegate. The MOU is included as Appendix B to 40 CFR 
part 112. An MOU between the Secretary of Transportation and the EPA 
Administrator, dated November 24, 1971 (36 FR 24080), established the 
definitions of non-transportation-related and transportation-related 
facilities. The definitions from the 1971 MOU are included as Appendix 
A to 40 CFR part 112.

B. Background of This Rulemaking

    Part 112 of 40 CFR outlines the requirements for both the 
prevention of and the response to oil spills. The prevention aspect of 
the rule requires preparation and implementation of Spill Prevention, 
Control, and Countermeasure (SPCC) Plans. This rulemaking affects SPCC 
and FRP requirements. The SPCC requirements were originally promulgated 
on December 11, 1973 (38 FR 34164), under the authority of section 
311(j)(1)(C) of the Act. The regulation established spill prevention 
procedures, methods, and equipment requirements for non-transportation-
related onshore and offshore facilities with aboveground storage 
capacity greater than 1,320 gallons (or greater than 660 gallons in a 
single container), or completely buried oil storage capacity greater 
than 42,000 gallons. Regulated facilities were also limited to those 
that, because of their location could reasonably be expected to 
discharge oil in harmful quantities into the navigable waters of the 
United States or adjoining shorelines.
    We have amended the SPCC requirements a number of times, and those 
amendments are described in an October 22, 1991 Federal Register 
proposed rule. 56 FR 54612. In the October 1991 document, in addition 
to the description of past amendments, EPA proposed new revisions that 
involved changes in the applicability of the regulation and the 
required procedures for the completion of SPCC Plans, as well as the 
addition of a facility notification provision. The proposed rule also 
reflected changes in the jurisdiction of section 311 of the Act made by 
amendments to the Act in 1977 and 1978. We have finalized some of those 
proposed revisions, with modifications, in this rule.
    On February 17, 1993, we again proposed clarifications of and 
technical changes to the SPCC rule. We also proposed facility response 
planning requirements to implement the Oil Pollution Act of 1990 (OPA). 
58 FR 8824. The proposed changes to the SPCC rule included 
clarifications of certain requirements, response plans for facilities 
without secondary containment, prevention training, and methods of 
determining whether a tank would be subject to brittle fracture. We 
promulgated the facility response planning requirements of the 1993 
proposal on July 1, 1994, (59 FR 34070), and they are codified at 40 
CFR 112.20-112.21. We have finalized the proposed 1993 prevention 
requirements, with modifications, in this rule.
    In 1996, EPA completed a survey and analysis of SPCC facilities. 
The survey was designed to ensure that data on the sampled facilities 
could be statistically extrapolated to the nation as a whole for all 
facilities regulated by EPA's SPCC regulation. We used the results of 
that survey and analysis to develop a proposed rule affecting SPCC 
facilities on December 2, 1997. 62 FR 63812. The survey and analytical 
results are part of the administrative record for this rulemaking.
    The purpose of the 1997 proposal was to reduce the information 
collection burden imposed by the prevention requirements in the SPCC 
rule and the FRP rule without creating an adverse impact on public 
health or the environment. We also proposed changes in information 
collection requirements for facility response plans, but have withdrawn 
them in this rulemaking. Those changes would have affected the 
calculation of storage capacity at certain facilities for response plan 
purposes. 62 FR 63816. However, see new Sec. 112.1(d)(6). The 1997 SPCC 
proposals, as modified, are finalized in this rule.
    On April 8, 1999, we proposed revision to facility response plan 
requirements. 64 FR 17227. The main purpose of the proposal was to 
provide a more specific methodology for planning response resources 
that can be used by an owner or operator of a facility that handles, 
stores, or transports animal fats and vegetable oils. We finalized that 
proposal on June 30, 2000. 65 FR 40776. The final rule included four 
new definitions that are applicable to all of part 112.

III. Summary of Major Rule Provisions

    For your convenience, we have developed a table showing a summary 
of the major revisions in this rule. The table does not always use 
exact rule text, but summarizes rule provisions. For exact rule text, 
see 40 CFR part 112 (2000) for text of the current rule; for exact text 
of the revised rule, see the rule text following this preamble.

          Summary of Major Revisions to the Current SPCC Rules
------------------------------------------------------------------------
      Current SPCC rule         Revised SPCC rule          Comment
------------------------------------------------------------------------
Section 112.1: General Applicability
------------------------------------------------------------------------

[[Page 47044]]

 
Sec.  112.1(b): Explains      Sec.  112.1(b):       Sec.  112.1(b): The
 that the SPCC rule applies    Explains that the     revised rule
 to owners or operators of     SPCC rule applies     clarifies that
 facilities that drill,        to owners or          users of oil are
 produce, gather, store,       operators of          also subject to the
 process, refine, transfer,    facilities that       rule. It also
 distribute, or consume oil    drill, produce,       expands the scope
 and oil products, and might   gather, store,        of the rule to
 reasonably be expected to     process, refine,      conform with the
 discharge oil in harmful      transfer,             expanded
 quantities into or upon       distribute, use, or   jurisdiction in the
 navigable waters of the       consume oil and oil   amended Clean Water
 United States or adjoining    products, and might   Act.
 shorelines.                   reasonably be
                               expected to
                               discharge oil in
                               quantities that may
                               be harmful into or
                               upon navigable
                               waters of the
                               United States or
                               adjoining
                               shorelines, or
                               waters of the
                               contiguous zone, or
                               in connection with
                               activities under
                               the Outer
                               Continental Shelf
                               Lands Act or
                               Deepwater Port Act,
                               or affecting
                               certain natural
                               resources.
Sec.  112.1(d)(2)(i):         Sec.  112.1(d)(2)(i)  Sec.  112.1(d)(2)(i)
 Section 112.1(d)(2) exempts   : Section             : The revised rule
 from the rule a facility      112.1(d)(2) exempts   provides that
 which meets both criteria     from the rule a       completely buried
 specified in Sec.             facility which        tanks subject to
 112.1(d)(2)(i) and (ii).      meets both criteria   all of the
 The first criterion, found    specified in Sec.     technical
 in Sec.  112.1(d)(2)(i) is:   112.1(d)(2)(i) and    requirements of
 the completely buried         (ii). The first       parts 280 or 281 do
 storage capacity of the       criterion, Sec.       not count in the
 facility is 42,000 gallons    112.1(d)(2)(i) is:    calculation of the
 or less of oil. The           the completely        42,000 gallon
 threshold applies to          buried storage        threshold. It also
 storage capacity contained    capacity of the       clarifies that
 in operating equipment as     facility is 42,000    permanently closed
 well as to storage capacity   gallons or less of    tanks do not count
 contained in tanks.           oil. For purposes     in the calculation
                               of this exemption,    of that threshold.
                               the completely        The threshold
                               buried storage        continues to apply
                               capacity of a         to storage capacity
                               facility does not     contained in
                               include the           operating equipment
                               capacity of           as well as to
                               completely buried     storage capacity
                               tanks, as defined     contained in tanks.
                               in Sec.  112.2,
                               that are currently
                               subject to all of
                               the technical
                               requirements of 40
                               CFR part 280 or all
                               of the technical
                               requirements of a
                               State program
                               approved under 40
                               CFR part 281. Also,
                               the completely
                               buried storage
                               capacity of a
                               facility does not
                               include the
                               capacity of
                               completely buried
                               tanks that are
                               ``permanently
                               closed,'' as
                               defined in Sec.
                               112.2. The
                               threshold applies
                               to storage capacity
                               contained in
                               operating equipment
                               as well as to
                               storage capacity
                               contained in tanks.
Sec.  112.1(d)(2)(ii): The    Sec.  112.1(d)(2)(ii  Sec.  112.1(d)(2)(ii
 second criterion, found in    ): The second         ): The revised rule
 Sec.  112.1(d)(2)(ii) is:     criterion found in    raises the
 the storage capacity, which   Sec.  112.1(d)(2)(i   threshold for
 is not buried, of the         i) is: the            aboveground storage
 facility is 1,320 gallons     aboveground storage   capacity by
 or less of oil, provided      capacity of the       eliminating the
 that no single container      facility is 1,320     provision that
 has a storage capacity of     gallons or less of    triggers the
 greater than 660 gallons.     oil. For purposes     requirement to
 The threshold applies to      of this exemption,    prepare and
 storage capacity contained    only containers of    implement an SPCC
 in operating equipment as     oil with a capacity   Plan if any single
 well as to storage capacity   of 55 gallons or      container has a
 in containers.                greater are           capacity greater
                               counted. The          than 660 gallons.
                               aboveground storage   It maintains the
                               capacity of a         greater than 1,320
                               facility does not     gallon threshold.
                               include the           The revised rule
                               capacity of           also establishes a
                               containers that are   de minimis
                               ``permanently         container capacity
                               closed,'' as          size to calculate
                               defined in 112.2.     aboveground storage
                               The threshold         capacity. Only
                               applies to storage    containers with a
                               capacity contained    capacity of 55
                               in operating          gallons or greater
                               equipment as well     are counted in the
                               as to storage         calculation of
                               capacity in           aboveground storage
                               containers.           capacity. The
                                                     revised rule
                                                     clarifies that
                                                     permanently closed
                                                     containers do not
                                                     count in the
                                                     calculation of
                                                     aboveground storage
                                                     capacity. The
                                                     threshold continues
                                                     to apply to storage
                                                     capacity contained
                                                     in operating
                                                     equipment as well
                                                     as to storage
                                                     capacity in
                                                     containers.
Sec.  112.1(d)(4): No         Sec.  112.1(d)(4):    Sec.  112.1(d)(4):
 counterpart in current rule.  Exempts from the      Completely buried
                               SPCC requirements     storage tanks
                               completely buried     subject to all of
                               storage tanks, as     the technical
                               defined in Sec.       requirements of 40
                               112.2, as well as     CFR part 280 or a
                               connected             State program
                               underground piping,   approved under 40
                               underground           CFR part 281 are no
                               ancillary             longer required to
                               equipment, and        comply with SPCC
                               containment           provisions, except
                               systems, when such    for the facility
                               tanks are subject     diagram. EPA
                               to all of the         estimates that
                               technical             under this new
                               requirements of 40    rule, most gasoline
                               CFR part 280 or a     service stations
                               State program         will drop out of
                               approved under 40     the SPCC program.
                               CFR part 281,
                               except that such
                               tanks must be
                               marked on the
                               facility diagram as
                               required by Sec.
                               112.7(a)(3), if the
                               facility is
                               otherwise subject
                               to this part.
Sec.  112.1(d)(5): No         Sec.  112.1(d)(5):    Sec.  112.1(d)(5):
 counterpart in current rule.  The revised rule      In response to
                               exempts containers    comments, EPA has
                               with a storage        established a
                               capacity of less      minimum size
                               than 55 gallons of    container for
                               oil from all SPCC     purposes of the
                               requirements.         regulatory
                                                     threshold.
                                                     Containers with a
                                                     storage capacity of
                                                     less than 55
                                                     gallons of oil are
                                                     exempt from all
                                                     SPCC requirements.

[[Page 47045]]

 
Sec.  112.1(d)(6): No         Sec.  112.1(d)(6):    Sec.  112.1(d)(6): A
 counterpart in current rule.  Exempts any           facility or part
                               facility or part      thereof used
                               thereof from the      exclusively for
                               rule, if used         wastewater
                               exclusively for       treatment will no
                               wastewater            longer be subject
                               treatment and not     to prevention
                               used to meet any      planning unless it
                               other requirement     is used to meet
                               of part 112. The      part 112
                               production,           requirements.
                               recovery, or
                               recycling of oil is
                               not wastewater
                               treatment for
                               purposes of this
                               paragraph.
Sec.  112.1(f): No            Sec.  112.1(f):       Sec.  112.1(f): This
 counterpart in current rule.  Notwithstanding any   amendment gives the
                               regulatory            Regional
                               exemptions, the       Administrator
                               Regional              authority to
                               Administrator may     require preparation
                               require that the      of an entire SPCC
                               owner or operator     plan, or applicable
                               of any facility       part, by an owner
                               subject to EPA        or operator of a
                               jurisdiction under    facility exempted
                               section 311(j) of     from SPCC
                               the Clean Water Act   requirements when
                               (CWA), prepare and    it becomes
                               implement an SPCC     necessary to
                               Plan, or any          achieve the
                               applicable part, to   purposes of the
                               carry out the         CWA. This authority
                               purposes of the       will be exercised
                               CWA. The rule         on a case-by-case
                               includes notice and   basis. The decision
                               appeal provisions.    to require a Plan
                                                     could be based on
                                                     the presence of
                                                     environmental
                                                     concerns not
                                                     adequately
                                                     addressed under
                                                     other regulations,
                                                     or other relevant
                                                     environmental
                                                     factors, for
                                                     example, discharge
                                                     history.
------------------------------------------------------------------------
Section 112.2--Definitions
------------------------------------------------------------------------
Sec.  112.2--definition of    Sec.  112.2--         Sec.  112.2--
 facility: No counterpart in   definition of         definition of
 current rule.                 facility:             facility: The
                               ``Facility'' is       revised rule
                               defined as any        clarifies that a
                               mobile or fixed,      facility may be as
                               onshore or offshore   small as a piece of
                               building,             equipment, for
                               structure,            example, a tank, or
                               installation,         as large as a
                               equipment, pipe, or   military base.
                               pipeline used in
                               oil well drilling
                               operations, oil
                               production, oil
                               refining, oil
                               storage, oil
                               gathering, oil
                               transfer, oil
                               distribution, and
                               waste treatment, or
                               in which oil is
                               used. . . .''
------------------------------------------------------------------------
Section 112.3: Requirement to prepare and implement Spill Prevention,
 Control, and Countermeasure Plan
------------------------------------------------------------------------
Sec.  112.3(a): An owner or   Sec.  112.3(a): An    Sec.  112.3(a): For
 operator of an onshore or     owner or operator     those facilities
 offshore facility in          (O/O) of an onshore   already in
 operation on or before        or offshore           operation on the
 January 10, 1974, that has    facility in           effective date of
 had a discharge to            operation on or       the rule, an owner
 navigable waters or           before August 16,     or operator of a
 adjoining shorelines, or,     2002, that has had    facility subject to
 due to its location, could    a discharge as        the rule must
 reasonably be expected to     described in Sec.     prepare an SPCC
 have a discharge to           112.1(b), or, due     Plan within the
 navigable waters or           to its location,      current time frame
 adjoining shorelines, must    could reasonably be   of six months. He
 prepare and fully implement   expected to have a    may take up to an
 an SPCC Plan, in writing      discharge as          additional six
 and in accordance with Sec.   described in Sec.     months to implement
  112.7. The owner or          112.1(b), must        the Plan. The
 operator must prepare the     prepare a written     revised rule
 Plan within 6 months, and     Plan in accordance    extends this same
 fully implement it as soon    with Sec.  112.7      time frame to
 as possible, but not later    and any other         amendments
 than within 1 year.           applicable section    necessary to bring
                               within 6 months of    the Plan into
                               the effective date    compliance with
                               of the rule, and      rule revisions. An
                               implement it as       owner or operator
                               soon as possible,     of a facility
                               but not later than    becoming
                               within 1 year of      operational after
                               the effective date    August 16, 2002
                               of the rule. The O/   through August 18,
                               O of facility that    2003 must prepare
                               becomes operational   and implement a
                               after August 16,      Plan not later than
                               2002 through August   August 18, 2003.
                               18, 2003 must
                               prepare and
                               implement a Plan
                               not later than
                               August 18, 2003.
Sec.  112.3(b): The owner or  Sec.  112.3(b): The   Sec.  112.3(b): The
 operator of an onshore and    owner or operator     owner or operator
 offshore facility that        of an onshore or      of a facility that
 becomes operational after     offshore facility     becomes operational
 January 10, 1974, and that    that becomes          after August 18,
 has had a discharge to        operational after     2003 must now
 navigable waters or           August 18, 2003,      prepare and
 adjoining shorelines, or      and could             implement an SPCC
 could reasonably be           reasonably be         Plan before
 expected to have a            expected to have a    beginning
 discharge to navigable        discharge as          operations. The
 waters or adjoining           described in Sec.     time frame in the
 shorelines, must prepare an   112.1(b), from that   current rule is up
 SPCC Plan. Unless the owner   facility, must        to 6 months for
 or operator is granted an     prepare and           Plan preparation
 extension of time to          implement an SPCC     and up to 6 months
 prepare and implement the     Plan before           more for Plan
 Plan by the Regional          beginning             implementation.
 Administrator, he must        operations.
 prepare the Plan within 6
 months and fully implement
 it as son as possible, but
 not later than within 1
 year.

[[Page 47046]]

 
Sec.  112.3(d): No SPCC Plan  Sec.  112.3(d): No    Sec.  112.3(d): The
 is effective to satisfy the   SPCC Plan is          revised rule adds
 requirements of the SPCC      effective to          specificity to the
 rule unless it has been       satisfy the           PE's attestation.
 reviewed and certified by a   requirements of the   The specificity
 Registered Professional       SPCC rule unless it   includes a
 Engineer (PE). By means of    has been reviewed     requirement that
 this certification the PE,    and certified by a    the PE consider
 having examined the           PE. By means of       applicable industry
 facility and being familiar   this certification    standards and
 with the provisions of the    the PE attests        certify that the
 SPCC rule, attests that the   that: (i) he is       Plan is prepared in
 SPCC Plan has been prepared   familiar with the     accordance with
 in accordance with good       requirements of the   part 112
 engineering practices. The    SPCC rule; (ii) he    requirements.
 PE's certification does not   or his agent has      Presently, the PE
 relieve the owner or          visited and           must attest only
 operator of an onshore or     examined the          that the Plan has
 offshore facility of his      facility; (iii) the   been prepared in
 duty to prepare and fully     Plan has been         accordance with
 implement the Plan in         prepared in           good engineering
 accordance with all           accordance with       practice. The
 applicable requirements.      good engineering      revised rule allows
                               practice, including   an agent of the PE
                               consideration of      to visit and
                               applicable industry   examine the
                               standards, and with   facility in place
                               the requirements of   of the PE, but the
                               the SPCC rule; (iv)   PE must review the
                               procedures for        agent's work, and
                               required              certify the Plan.
                               inspections and
                               testing have been
                               established; and,
                               (v) the Plan is
                               adequate for the
                               facility. The PE's
                               certification does
                               not relieve the
                               owner or operator
                               of an onshore or
                               offshore facility
                               of his duty to
                               prepare and fully
                               implement the Plan
                               in accordance with
                               all applicable
                               requirements.
Sec.  112.3(e): An owner or   Sec.  112.3(e): An    Sec.  112.3(e): The
 operator of a facility for    owner or operator     revised rule
 which an SPCC Plan is         of a facility for     requires the
 required must maintain a      which an SPCC Plan    facility owner or
 complete copy of the Plan     is required must      operator to
 at the facility if the        maintain a complete   maintain a copy of
 facility is attended as       copy of the Plan at   the Plan at the
 least 8 hours per day, or     the facility if the   facility if it is
 at the nearest field office   facility is           attended at least 4
 if the facility is not so     attended at least 4   hours a day, in
 attended, and must make the   hours per day, or     contrast to the
 Plan available to the         at the nearest        current requirement
 Regional Administrator for    field office if the   to maintain it at
 on-site review during         facility is not so    the facility if it
 normal working hours.         attended, and must    is attended at
                               make the Plan         least 8 hours a
                               available to the      day.
                               Regional
                               Administrator for
                               on-site review
                               during normal
                               working hours.
Sec.  112.3(f): The Regional  Sec.  112.3(f): The   Sec.  112.3(f): The
 Administrator may authorize   Regional              revised rule
 an extension of time for      Administrator may     provides for
 the preparation and           authorize an          extension for
 implementation of an SPCC     extension of time     amendments of the
 Plan, when he finds that      for the preparation   Plan, as well as
 the owner or operator         and implementation    the entire Plan.
 cannot comply with all SPCC   of an SPCC Plan, or
 requirements as a result of   any amendment
 either nonavailability of     thereto, when he
 qualified personnel, or       finds that the
 delays in construction or     owner or operator
 equipment delivery beyond     cannot comply with
 his control and without his   all SPCC
 fault, or the fault of his    requirements as a
 agents or employees. The      result of either
 rule also specifies what      nonavailability of
 the letter requesting an      qualified
 extension must contain.       personnel, or
                               delays in
                               construction or
                               equipment delivery
                               beyond his control
                               and without his
                               fault, or the fault
                               of his agents or
                               employees. The rule
                               also specifies what
                               the letter
                               requesting an
                               extension must
                               contain.
------------------------------------------------------------------------
Section 112.4: Amendment of Spill Prevention, Control, and
 Countermeasures Plan by Regional Administrator
------------------------------------------------------------------------
Sec.  112.4(a): Whenever an   Sec.  112.4(a):       Sec.  112.4(a): We
 SPCC facility has: (1)        Whenever an SPCC      have revised the
 discharged more than 1,000    facility has: (1)     geographic scope of
 U.S. gallons of oil into or   discharged more       the rule in
 upon the navigable waters     than 1,000 U.S.       accordance with the
 of the United States or       gallons of oil in a   CWA amendments, by
 adjoining shorelines in a     single discharge as   using the phase
 single discharge to           described in Sec.     ``discharge as
 navigable waters or           112.1(b), or (2)      described in Sec.
 adjoining shorelines, or      discharged more       112.1(b).'' We also
 (2) discharged oil in         than 42 U.S.          raised the
 harmful quantities, as        gallons of oil, as    threshold for
 defined in 40 CFR part 110,   described in Sec.     reporting two
 into or upon the navigable    112.1(b), in each     discharges as
 waters of the United States   of 2 discharge,       described in Sec.
 or adjoining shorelines in    within any 12-month   112.1(b), from a
 each of 2 discharges to       period, the owner     ``reportable''
 navigable waters or           or operator of the    quantity under the
 adjoining shorelines,         facility must         Clean Water Act, to
 reportable under section      submit to the RA,     a threshold of more
 311(b)(5) of the Clean        within 60 days from   than 42 U.S.
 Water Act, within any 12-     the time the          gallons, or 1
 month period, the owner or    facility becomes      barrel, in each of
 operator of the facility      subject to this       those discharges.
 must submit to the Regional   section, 8            The 1,000 gallon
 Administrator (RA), within    different items of    threshold for a
 60 days from the time the     information, plus     single discharge as
 facility becomes subject to   additional            described in Sec.
 this section, 10 different    information           112.1(b) remains
 items of information, plus    pertinent to the      unchanged. We also
 additional information        Plan if the RA        reduced the amount
 pertinent to the Plan if      requests it.          of information that
 the RA requests it.                                 must minimally be
                                                     submitted to the
                                                     RA.
Sec.  112.4(b): Section       Sec.  112.4(b):       Sec.  112.4(b):
 112.4 does not apply until    Section 112.4 does    Section 112.3 in
 the expiration of the time    not apply until the   the revised rule
 permitted for the             expiration of the     allows more time
 preparation and               time permitted for    for some facilities
 implementation of the Plan    the preparation and   for preparation and
 under Sec.  112.3.            implementation of     implementation of a
                               the Plan under Sec.   Plan, or any
                                112.3.               amendments thereto,
                                                     than in the 1991
                                                     proposed rule.
                                                     Therefore, the
                                                     implementation of
                                                     the requirements of
                                                     Sec.  112.4 is
                                                     postponed until the
                                                     new time frames in
                                                     Sec.  112.3 have
                                                     passed.

[[Page 47047]]

 
Sec.  112.4(c): The owner or  Sec.  112.4(c): The   Sec.  112.4(c): The
 operator is required to       owner or operator     revised rule
 provide the same              is required to        changes the
 information he provided to    provide the same      requirement from
 EPA, under Sec.  112.4(a),    information he        notification to the
 to the State agency in        provided to EPA,      State agency in
 charge of water pollution     under Sec.            charge of water
 control activities in and     112.4(a), to the      pollution control
 for the State in which the    State agency in       activities to
 facility is located at the    charge of oil         notification to the
 same time he provides it to   pollution control     State agency in
 EPA. After receiving that     activities in the     charge of oil
 information, the State        State in which the    pollution control
 agency may conduct a review   facility is located   activities. There
 and make recommendations to   at the same time he   may be more than
 the Regional Administrator    provides it to EPA.   one such agency in
 as to further procedures,     After receiving       some States.
 methods, equipment and        that information,
 other requirements for        the State agency or
 equipment necessary to        agencies may
 prevent and to contain        conduct a review
 discharges of oil from the    and make
 facility.                     recommendations to
                               the Regional
                               Administrator as to
                               further procedures,
                               methods, equipment
                               and other
                               requirements for
                               equipment necessary
                               to prevent and to
                               contain discharges
                               of oil from the
                               facility.
Sec.  112.4(d): This section  Sec.  112.4(d): This  Sec.  112.4(d): The
 allows the Regional           section allows the    revised rule
 Administrator to require a    Regional              provides that the
 facility owner or operator    Administrator to      Regional
 to amend his Plan after       require a facility    Administrator may
 review of materials the       owner or operator     require Plan
 owner or operator submits     to amend his Plan     amendment after on-
 under Sec.  112.4 (a) and     after review of       site review of the
 (c).                          materials the owner   Plan.
                               or operator submits
                               under Sec.  112.4
                               (a) and (c), or
                               after on-site
                               review of the Plan.
------------------------------------------------------------------------
Section 112.5: Amendment of Spill Prevention, Control, and
 Countermeasures Plan by owners or operators
------------------------------------------------------------------------
Sec.  112.5(b): This section  Sec.  112  Sec.  112.5(b): The
 requires an owner or          .5(b): This section   revised rule
 operator to review his Plan   requires an owner     changes the period
 at least every 3 years from   or operator to        of review for SPCC
 the date a facility becomes   review his Plan at    Plans from 3 to 5
 subject to the SPCC rule.     least every 5 years   years. It also
 As a result of this review    from the date a       requires
 and evaluation, the owner     facility becomes      documentation of
 or operator must amend the    subject to the SPCC   completion of the
 SPCC Plan within 6 months     rule; or for an       review and
 of the review to include      existing facility,    evaluation.
 more effective prevention     5 years from the
 and control technology if:    date the last
 (1) Such technology will      review was required
 significantly reduce the      under this part.
 likelihood of a discharge     The owner or
 to navigable waters or        operator must amend
 adjoining shorelines from     the SPCC Plan
 the facility; and (2) if      within 6 months of
 such technology has been      the review to
 field-proven at the time of   include more
 the review.                   effective
                               prevention and
                               control technology
                               if: (1) Such
                               technology will
                               significantly
                               reduce the
                               likelihood of a
                               discharge as
                               described in Sec.
                               112.1(b) from the
                               facility; and (2)
                               if such technology
                               has been field-
                               proven at the time
                               of the review.
                               Implementation of
                               amendments is
                               required within 6
                               months following
                               amendment. The
                               owner or operator
                               must document
                               completion of the
                               review and
                               evaluation, and
                               must sign a
                               statement as to
                               whether he will
                               amend the Plan,
                               either at the
                               beginning or end of
                               the Plan or in a
                               log or an appendix
                               to the Plan. The
                               following will
                               suffice, ``I have
                               completed review
                               and evaluation of
                               the SPCC Plan for
                               (name of facility)
                               on (date), and will
                               (will not) amend
                               the Plan as a
                               result.''
Sec.  112.5(c): This section  Sec.  112.5(c): This  Sec.  112.5(c): The
 requires that a               section requires      revised rule
 Professional Engineer         that a Professional   clarifies that a
 certify any amendments to     Engineer certify      Professional
 an SPCC Plan.                 any technical         Engineer must
                               amendments to an      certify only
                               SPCC Plan.            technical
                                                     amendments. PE
                                                     certification is
                                                     not required for
                                                     non-technical
                                                     amendments, like
                                                     changes to phone
                                                     numbers, names,
                                                     etc.
------------------------------------------------------------------------
Section 112.7: Spill Prevention, Control, and Countermeasure Plan
 general requirements. We have reorganized Sec.  112.7 of the current
 regulation into Secs.  112.7, 112.8, 112.9, 112.10, 112.11, 112.12,
 112.13, 112.14, and 112.15 of the final rule based on facility type and
 type of oil.
------------------------------------------------------------------------

[[Page 47048]]

 
Sec.  112.7: This section     Sec.  112.7: This     Sec.  112.7: The
 specifies that a Plan must    section specifies     revised rule allows
 be prepared in accordance     that a Plan must be   differing formats
 with good engineering         prepared in           for the Plan, other
 practices, and have the       accordance with       than the one format
 full approval of management   good engineering      now specified.
 at a level with authority     practices, and have   While you may use
 to commit the necessary       the full approval     the format
 resources. The SPCC Plan      of management at a    specified in the
 must follow the sequence      level with            rule, you may also
 specified in the rule, and    authority to commit   use other formats,
 include a discussion of the   the necessary         such as State
 facility's conformance with   resources. The SPCC   plans, Integrated
 the requirements of the       Plan must follow      Contingency Plans,
 rule.                         the sequence          and any other
                               specified in the      formats acceptable
                               rule, and include a   to the Regional
                               discussion of the     Administrator. If
                               facility's            you use another
                               conformance with      format, you must
                               the requirements of   cross-reference its
                               the rule. If you do   provisions to the
                               not follow the        requirement listed
                               sequence specified    in the SPCC rule.
                               in the rule, you      Also, if you use
                               must prepare an       another format, you
                               equivalent            must ensure that
                               prevention Plan       the format includes
                               acceptable to the     all applicable SPCC
                               Regional              requirements, or
                               Administrator that    you must supplement
                               meets all             that format to
                               applicable            include all
                               requirements, and     applicable SPCC
                               you must supplement   requirements.
                               it with section
                               cross-referencing
                               the location of
                               requirements listed
                               in the SPCC rule to
                               the equivalent
                               requirements in the
                               other prevention
                               plan.
Sec.  112.7(a)(2): No         Sec.  112.7(a)(2):    Sec.  112.7(a)(2):
 counterpart in current rule.  This provision        The revised rule
                               explicitly allows     explicitly allows
                               deviations from       deviations from
                               most of the rule's    most of the rule's
                               substantive           substantive
                               requirements          requirements
                               (except for           (except for
                               secondary             secondary
                               containment           containment
                               requirements),        requirements),
                               provided that you     provided that you
                               explain your          explain your
                               reasons for           reasons for
                               nonconformance with   nonconformance with
                               the requirement,      the requirement,
                               and provide           and provide
                               equivalent            equivalent
                               environmental         environmental
                               protection with an    protection with an
                               alternate measure.    alternate measure.
                               If the Regional       If the Regional
                               Administrator         Administrator
                               determines that the   determines that the
                               alternate measure     alternate measure
                               described in your     described in your
                               Plan does not         Plan does not
                               provide equivalent    provide equivalent
                               protection, he may    protection, he may
                               require that you      require that you
                               amend the Plan.       amend your Plan.
Sec.  112.7(a)(3): No         Sec.  112.7(a)(3):    Sec.  112.7(a)(3):
 counterpart in current rule.  This section          The facility
                               requires a facility   diagram must
                               owner or operator     include completely
                               to describe the       buried tanks
                               physical layout of    exempted from other
                               the facility and      SPCC requirements.
                               include a facility
                               diagram in the Plan.
Sec.  112.7(c): This section  Sec.  112.7(c): This  Sec.  112.7(c): The
 is the general provision      section is the        revised rule
 requiring secondary           general provision     maintains the
 containment.                  requiring secondary   current standard
                               containment.          that dikes, berms,
                                                     or retaining walls
                                                     must be
                                                     ``sufficiently
                                                     impervious'' to
                                                     contain oil. We
                                                     withdrew the
                                                     proposed standard
                                                     that such secondary
                                                     containment must be
                                                     impermeable for 72
                                                     hours.
Sec.  112.7(d): When it is    Sec.  112.7(d): When  Sec.  112.7(d): The
 not practicable to install    it is not             revised rule adds
 secondary containment at      practicable to        new requirements
 your facility, this section   install secondary     for periodic
 requires that you explain     containment at your   integrity testing
 why and provide a strong      facility, this        of containers, and
 oil spill contingency plan    section requires      periodic integrity
 in your SPCC Plan. The        that you explain      and leak testing of
 contingency plan must         why and provide a     valves and piping.
 follow the provisions of 40   strong oil spill      We clarify that if
 CFR part 109. You must also   contingency plan in   you have submitted
 provide in your SPCC Plan a   your SPCC Plan. The   a facility response
 written commitment to         contingency plan      plan under Sec.
 manpower, equipment and       must follow the       112.20 for a
 materials required to         provisions of 40      facility, you need
 expeditiously control and     CFR part 109. You     not provide for
 remove any harmful quantity   must also provide     that facility
 of oil discharged.            in your SPCC Plan a   either a
                               written commitment    contingency plan
                               to manpower,          following the
                               equipment and         provisions of part
                               materials required    109, nor a written
                               to expeditiously      commitment of
                               control and remove    manpower,
                               any quantity of oil   equipment, and
                               discharged that may   materials required
                               be harmful; conduct   to expeditiously
                               periodic integrity    control and remove
                               testing of the        any quantity of oil
                               containers; and,      discharged that may
                               conduct periodic      be harmful.
                               integrity and leak
                               testing of the
                               valves and piping.
Sec.  112.7(e)(8): This       Sec.  112.7(e): This  Sec.  112.7(e): The
 section requires that the     section requires      revised rule allows
 owner or operator conduct     that the owner or     use of usual and
 required inspections in       operator conduct      customary business
 accordance with written       required              records to serve as
 procedures developed for      inspections and       a record of tests
 the facility. The owner or    tests in accordance   or inspections,
 operator must maintain        with written          instead of keeping
 these written procedures      procedures            duplicate records.
 and a record of               developed by him or   It also allows the
 inspections, signed by the    by the certifying     owner or operator
 appropriate supervisor or     engineer for the      to keep those
 inspector, as part of the     facility. The owner   records as an
 SPCC Plan, and maintain       or operator must      appendix to the
 them for a period of 3        maintain these        Plan, or in a
 years.                        written procedures    separate log, etc.,
                               and a record of       with the Plan,
                               inspections and       rather than
                               tests, signed by      requiring that
                               the appropriate       those records be a
                               supervisor or         part of the Plan.
                               inspector, with the   The rule also
                               SPCC Plan, and        acknowledges that
                               maintain them for a   the certifying
                               period of 3 years.    engineer, as well
                               Records of            as the owner or
                               inspections and       operator, has a
                               tests kept pursuant   role in the
                               to usual and          development of
                               customary business    inspection
                               practices are         procedures.
                               sufficient for
                               purposes of the
                               rule.

[[Page 47049]]

 
Sec.  112.7(e)(10): The       Sec.  112.7(f): The   Sec.  112.7(f): The
 owner or operator of a        owner or operator     revised rule
 facility is responsible for   of a facility, at a   mandates training
 properly instructing          minimum, must train   only for oil-
 personnel in the operation    oil-handling          handling employees,
 and maintenance of            personnel in the      instead of all
 equipment to prevent the      operation and         employees. It
 discharges of oil and         maintenance of        specifies
 applicable pollution          equipment to          additional topics
 control laws, rules, and      prevent the           for the training of
 regulations. An owner or      discharge of oil;     these employees. It
 operator must designate a     discharge procedure   also specifies that
 person at each facility who   protocols;            discharge
 is accountable for oil        applicable            prevention
 discharge prevention and      pollution control     briefings must be
 who reports to facility       laws, rules, and      conducted at least
 management. An owner or       regulations;          once a year,
 operator must schedule and    general facility      instead of at
 conduct discharge             operations; and,      ``intervals
 prevention briefings for      the contents of the   frequent enough to
 operating personnel at        facility Plan. An     assure adequate
 intervals frequent enough     owner or operator     understanding of
 to assure adequate            must designate a      the SPCC Plan for
 understanding of the SPCC     person at each        that facility.''
 Plan for that facility.       facility who is
 Such briefings must           accountable for oil
 highlight and describe        discharge
 known discharges to           prevention and who
 navigable waters or           reports to facility
 adjoining shorelines, or      management. An
 failures, malfunctioning      owner or operator
 components, and recently      must schedule and
 developed precautionary       conduct discharge
 measures.                     prevention
                               briefings for oil-
                               handling personnel
                               at least once a
                               year to assure
                               adequate
                               understanding of
                               the SPCC Plan for
                               that facility. Such
                               briefings must
                               highlight and
                               describe known
                               discharges as
                               described in Sec.
                               112.1(b), or
                               failures,
                               malfunctioning
                               components, and
                               recently developed
                               precautionary
                               measures.
------------------------------------------------------------------------
Sec.  112.7(i): No            Sec.  112.7(i): This  Sec.  112.7(i): The
 counterpart in current rule.  section requires      brittle fracture
                               evaluation for        requirement was
                               field-constructed     triggered by the
                               aboveground           Ashland Oil tank
                               containers            collapse in 1988
                               undergoing repair,    due to brittle
                               alteration,           fracture.
                               reconstruction, or
                               change in service
                               that might affect
                               the risk of a
                               discharge or
                               failure due to
                               fracture or other
                               catastrophe. It
                               also requires such
                               evaluation when
                               there has actually
                               been a discharge or
                               failure due to
                               brittle fracture or
                               other catastrophe.
------------------------------------------------------------------------
Section 112.8: Requirements for onshore facilities (excluding production
 facilities).
------------------------------------------------------------------------
Sec.  112.7(e)(2)(iii): This  Sec.  112.8(c)(3):    Sec.  112.8(c)(3):
 section establishes           This section          The revised rule
 substantive requirements      establishes           allows records
 for stormwater drainage       substantive           required by NPDES
 from diked areas, and         requirements for      permit regulations
 recordkeeping requirements    stormwater drainage   to record
 for stormwater bypass         from diked areas,     stormwater bypass
 events.                       and recordkeeping     events to be used
                               requirements for      for SPCC purposes
                               stormwater bypass     in lieu of events
                               events. The revised   records
                               rule provides that    specifically
                               records required      prepared for
                               under permits         purpose.
                               issued in
                               accordance with the
                               National Pollutant
                               Discharge
                               Elimination Systems
                               (NPDES) rules are
                               sufficient for
                               recording
                               stormwater bypass
                               events.
Sec.  112.7(e)(2)(vi): This   Sec.  112.8(c)(6):    Sec.  112.8(c)(6):
 provision requires that       The revised rule      The revised rule
 aboveground containers be     requires that         requires that an
 subject to periodic           aboveground           owner or operator
 integrity testing, taking     containers be         test aboveground
 into account tank design      tested for            containers for
 (floating roof, etc.) and     integrity on a        integrity on a
 using such techniques as      regular schedule,     regular schedule,
 hydrostatic testing, visual   and when material     and when material
 inspection, or a system of    repairs are done.     repairs are done.
 non-destructive shell         The frequently and    The rationale for
 thickness testing. The        type of testing       adding a testing
 owner or operator must keep   must take into        requirement when
 comparison records where      account container     material repairs
 appropriate, and must         size and design       are done is that
 include tank supports and     (floating roof,       material repairs
 foundations in these          skid-mounted,         might increase the
 inspections. In addition,     elevated, partially   potential for oil
 operating personnel must      buried, for           discharges. Usual
 frequently inspect the        example). The owner   and customary
 outside of the container      or operator must      business records
 for signs of deterioration,   combine visual        may be used for the
 leaks, or accumulation of     inspection with       purpose of
 oil inside diked areas.       another testing       integrity testing,
                               technique such as     instead of records
                               hydrostatic           specifically
                               testing,              created for this
                               radiographic          purpose.
                               testing, ultrasonic
                               testing, acoustic
                               emissions testing,
                               or other system of
                               non-destructive
                               shell testing. The
                               owner or operator
                               must keep
                               comparison records
                               and must include
                               tank supports and
                               foundations in
                               these inspections.
                               In addition,
                               operating personnel
                               must frequently
                               inspect the outside
                               of the container
                               for signs of
                               deterioration,
                               leaks, or
                               accumulation of oil
                               inside diked areas.
                               Records of
                               inspections and
                               tests kept pursuant
                               to usual and
                               customary business
                               practices are
                               sufficient for
                               purposes of the
                               rule.

[[Page 47050]]

 
Sec.  112.7(e)(3)(i): This    Sec.  112.8(d)(1):    Sec.  112.8(d)(1):
 section requires that         This section          The revised rule
 buried piping installations   requires that         requires that all
 have protective wrapping      buried piping that    buried piping that
 and coating and cathodic      is installed or       is installed or
 protection, if soil           replaced on or        replaced on or
 conditions warrant.           after August 16,      after August 16,
                               2002 must have        2002 must have
                               protective wrapping   protective wrapping
                               and coating and       and coating and
                               cathodic              cathodic
                               protection, or        protection, or
                               otherwise satisfy     otherwise satisfy
                               the corrosion         the corrosion
                               protection            protection
                               provisions for        provisions for
                               piping in 40 CFR      piping in 40 CFR
                               part 280 or a State   part 280 or a State
                               program approved      program approved
                               under 40 CFR part     under 40 CFR part
                               281.                  281, for all soil
                                                     conditions.
------------------------------------------------------------------------
Section 112.9: Requirements for onshore oil production facilities.
------------------------------------------------------------------------
Sec.  112.7(e)(5)(ii): This   Sec.  112.9(b)(1):    Sec.  112.9(b)(1):
 section provides              This section          The revised rule
 requirements for stormwater   provides              provides that
 drainage events.              requirements for      records required by
                               stormwater drainage   NPDES permit
                               events.               regulations are
                                                     allowable to record
                                                     stormwater bypass
                                                     events for SPCC
                                                     purposes in lieu of
                                                     records
                                                     specifically
                                                     generated for that
                                                     purpose.
Sec.  112.7(e)(5)(iii)(B):    Sec.  112.9(c)(2):    Sec.  112.9(c)(2):
 This section requires         This section          The revised rule
 secondary containment for     requires secondary    clarifies that the
 onshore production            containment for       secondary
 facilities.                   onshore production    containment must
                               facilities.           include sufficient
                                                     freeboard to
                                                     contain
                                                     precipitation.
------------------------------------------------------------------------

IV. Discussion of Issues

    Below is a discussion of the major issues for which we solicited 
comments in the 1991, 1993, and 1997 proposals. We also discuss the use 
of industry standards to comply with the rule. Following these issues, 
we discuss the revisions to each section and the major comments 
received, as well as responses to those comments. A detailed Response 
to Comments document addressing all comments is also part of this 
rulemaking and may be found in the administrative record for this rule.

A. Reorganization of the Rule

Background
    In 1991, EPA proposed to reorganize the SPCC rule based on facility 
type. The purpose of that proposed reorganization was to clarify SPCC 
Plan requirements for different types of facilities. In this 
rulemaking, we are dividing the rule into subparts. Subpart A consists 
of an applicability section, definitions, and general requirements for 
all facilities. Subparts B and C outline the requirements for different 
types of facilities storing and using different types of oils. Subpart 
B is for facilities storing or using petroleum oils or other non-
petroleum oils, except those oils covered by subpart C. Subpart C is 
for facilities storing or using animal fats and oils and greases, or 
fish and marine mammal oils; and, oils of vegetable origin, including 
oils from seeds, nuts, fruits, and kernels. Subpart D is for response 
requirements.
    If you have already prepared an SPCC Plan, you were required to 
follow the sequence of Sec. 112.7 of the current rule, prior to today's 
revisions. Today, we are reorganizing that portion of the rule into 
Secs. 112.7 through 112.15, based on facility type and type of oil. 
Under the introduction to Sec. 112.7 of today's rule, if your Plan does 
not follow the revised sequence, you must supplement it with a section 
cross-referencing the location of requirements listed in the revised 
rule and the equivalent requirements in your Plan. To assist you in 
preparing this cross-reference, the following table lists each 
requirement in the revised rule, provides the corresponding paragraph 
of the current rule, and leaves a space where you can show the location 
of the provision in your Plan. We have put this rule, including the 
table below, on our website for your convenience. You may download it 
for your use. See our Web site at www.epa.gov/oilspill.
    Under the revised rule, Sec. 112.7 sets out the general 
requirements for SPCC Plans for all facilities and all types of oil. 
Sections 112.8 to 112.11 set out the SPCC Plan requirements for 
petroleum oil and for non-petroleum oils other than animal fats and 
vegetable oils. Sections 112.12 to 112.15 set out the SPCC Plan 
requirements for animal fats and oils and greases, and fish and marine 
mammal oils; and for oils of vegetable origin, including oils from 
seeds, nuts, fruits, and kernels.

----------------------------------------------------------------------------------------------------------------
               Revised rule                        Current rule                Description of rule         Page
----------------------------------------------------------------------------------------------------------------
Sec.  112.7..............................  Sec.  112.7................  General requirements for SPCC     ......
                                                                         Plans for all facilities and
                                                                         all oil types.
Sec.  112.7(a)...........................  Sec.  112.7................  General requirements; discussion  ......
                                                                         of facility's conformance with
                                                                         rule requirements; deviations
                                                                         from Plan requirements;
                                                                         facility characteristics that
                                                                         must be described in the Plan;
                                                                         spill reporting information in
                                                                         the Plan; emergency procedures.
Sec.  112.7(b)...........................  Sec.  112.7(b).............  Fault analysis..................  ......
Sec.  112.7(c)...........................  Sec.  112.7(c).............  Secondary containment...........  ......
Sec.  112.7(d)...........................  Sec.  112.7(d).............  Contingency planning............  ......
Sec.  112.7(e)...........................  Sec.  112.7(e)(8)..........  Inspections, tests, and records.  ......
Sec.  112.7(f)...........................  Sec.  112.7(e)(10).........  Employee training and discharge   ......
                                                                         prevention procedures.
Sec.  112.7(g)...........................  Sec.  112.7(e)(9)..........  Security (excluding oil           ......
                                                                         production facilities).
Sec.  112.7(h)...........................  Sec.  112.7(e)(4)..........  Loading/unloading (excluding      ......
                                                                         offshore facilities).
Sec.  112.7(i)...........................  n/a........................  Brittle fracture evaluation       ......
                                                                         requirements.
Sec.  112.7(j)...........................  Sec.  112.7(e).............  Conformance with State            ......
                                                                         requirements.

[[Page 47051]]

 
Sec.  112.8 Sec.  112.12.................  Sec.  112.7(e)(1)..........  Requirements for onshore          ......
                                                                         facilities (excluding
                                                                         production facilities).
Sec.  112.8(a), Sec.  112.12(a)..........  n/a........................  General and specific              ......
                                                                         requirements.
Sec.  112.8(b), Sec.  112.12(b)..........  Sec.  112.7(e)(1)..........  Facility drainage...............  ......
Sec.  112.8(c), Sec.  112.12(c)..........  Sec.  112.7(e)(2)..........  Bulk storage containers.........  ......
Sec.  112.8(d), Sec.  112.12(d)..........  Sec.  112.7(e)(3)..........  Facility transfer operations,     ......
                                                                         pumping, and facility process.
Sec.  112.9, Sec.  112.13................  Sec.  112.7(e)(5)..........  Requirements for onshore          ......
                                                                         production facilities.
Sec.  112.9(a), Sec.  112.13(a)..........  n/a........................  General and specific              ......
                                                                         requirements.
Sec.  112.9(b), Sec.  112.13(b)..........  Sec.  112.7(e)(5)(ii)......  Oil production facility drainage  ......
Sec.  112.9(c), Sec.  112.13(c)..........  Sec.  112.7(e)(5)(iii).....  Oil production facility bulk      ......
                                                                         storage containers.
Sec.  112.9(d), Sec.  112.13(d)..........  Sec.  112.7(e)(5)(iv)......  Facility transfer operations,     ......
                                                                         oil production facility.
Sec.  112.10, Sec.  112.14...............  Sec.  112.7(e)(6)..........  Requirements for onshore oil      ......
                                                                         drilling and workover
                                                                         facilities.
Sec.  112.10(a), Sec.  112.14(a).........  n/a........................  General and specific              ......
                                                                         requirements.
Sec.  112.10(b), Sec.  112.14(b).........  Sec.  112.7(e)(6)(i).......  Mobile facilities...............  ......
Sec.  112.10(c), Sec.  112.14(c).........  Sec.  112.7(e)(6)(ii)......  Secondary containment--catchment  ......
                                                                         basins or diversion structures.
Sec.  112.10(d), Sec.  112.14(d).........  Sec.  112.7(e)(6)(iii).....  Blowout prevention (BOP)........
Sec.  112.11, Sec.  112.15...............  Sec.  112.7(e)(7)..........  Requirements for offshore oil     ......
                                                                         drilling, production, or
                                                                         workover facilities.
Sec.  112.11(a), Sec.  112.15(a).........  n/a........................  General and specific              ......
                                                                         requirements.
Sec.  112.11(b), Sec.  112.15(b).........  Sec.  112.7(e)(7)(ii)......  Facility drainage...............  ......
Sec.  112.11(c), Sec.  112.15(c).........  Sec.  112.7(e)(7)(iii).....  Sump systems....................  ......
Sec.  112.11(d), Sec.  112.15(d).........  Sec.  112.7(e)(7)(iv)......  Discharge prevention systems for  ......
                                                                         separators and treaters.
Sec.  112.11(e), Sec.  112.15(e).........  Sec.  112.7(e)(7)(v).......  Atmospheric storage or surge      ......
                                                                         containers; alarms.
Sec.  112.11(f), Sec.  112.15(f).........  Sec.  112.7(e)(7)(vi)......  Pressure containers; alarm        ......
                                                                         systems.
Sec.  112.11(g), Sec.  112.15(g).........  Sec.  112.7(e)(7)(vii).....  Corrosion protection............  ......
Sec.  112.11(h), Sec.  112.15(h).........  Sec.  112.7(e)(7)(viii)....  Pollution prevention system       ......
                                                                         procedures.
Sec.  112.11(i), Sec.  112.15(i).........  Sec.  112.7(e)(7)(ix)......  Pollution prevention systems;     ......
                                                                         testing and inspection.
Sec.  112.11(j), Sec.  112.15(j).........  Sec.  112.7(e)(7)(x).......  Surface and subsurface well shut- ......
                                                                         in valves and devices.
Sec.  112.11(k), Sec.  112.15(k).........  Sec.  112.7(e)(7)(xi)......  Blowout prevention..............  ......
Sec.  112.11(l), Sec.  112.15(l).........  Sec.  112.7(e)(7)(xiv).....  Manifolds.......................  ......
Sec.  112.11(m), Sec.  112.15(m).........  Sec.  112.7(e)(7)(xv)......  Flowlines, pressure sensing       ......
                                                                         devices.
Sec.  112.11(n), Sec.  112.15(n).........  Sec.  112.7(e)(7)(xvi).....  Piping; corrosion protection....  ......
Sec.  112.11(o), Sec.  112.15(o).........  Sec.  112.7(e)(7)(xvii)....  Sub-marine piping; environmental  ......
                                                                         stresses.
Sec.  112.11(p), Sec.  112.15(p).........  Sec.  112.7(e)(7)(xviii)...  Inspections of sub-marine piping  ......
----------------------------------------------------------------------------------------------------------------

    In 1995, Congress enacted the Edible Oil Regulatory Reform Act 
(EORRA), 33 U.S.C. 2720. That statute mandates that most Federal 
agencies differentiate between and establish separate classes for 
various types of oils, specifically: animal fats and oils and greases, 
and fish and marine mammal oils; oils of vegetable origin; petroleum 
oils, and other non-petroleum oils and greases. In differentiating 
between these classes of oils, Federal agencies are directed to 
consider differences in the physical, chemical, biological, and other 
properties, and in the environmental effects, of the classes. In 
response to EORRA, as noted above, we have divided the requirements of 
the rule by subparts for facilities storing or using the various 
classes of oils listed in that act.
    Because at the present time EPA has not proposed differentiated 
SPCC requirements for public notice and comment, the requirements for 
facilities storing or using all classes of oil will remain the same. 
However, we have published an advance notice of proposed rulemaking 
seeking comments on how we might differentiate among the requirements 
for the facilities storing or using various classes of oil. 64 FR 
17227, April 8, 1999. If after considering these comments, there is 
adequate justification for differentiation among the requirements for 
those facilities, we will propose rule changes.

B. Plain Language Format

    We have rewritten the SPCC rule in a plain language format to make 
it clearer and easier to use. A plain language format includes maximum 
use of the active voice; short, clear sentences; and, in this rule, a 
summary table of the major regulatory changes. This format is part of 
the Agency's ongoing efforts in regulatory reinvention. While we have 
made substantive changes in some provisions, the plain language changes 
are only editorial. The plain language format used in today's rule may 
appear different from other rules, but it establishes binding, 
enforceable legal requirements.
    In this preamble, as in the rule text, we often use the pronoun 
``he'' as a generic term. ``He'' does not necessarily mean a man; it 
may be a woman, or in some cases, a business organization when 
referring to an owner or operator.

C. ``Should to Shall to Must'' Clarification

Background
    EPA has always considered that Sec. 112.3 of the SPCC rule requires 
that SPCC Plans be prepared in accordance with Sec. 112.7, which in 
turn requires that Plans be prepared in accordance with good 
engineering practice. However, clarification of the current rule is 
necessary because of confusion on the part of some facility owners or 
operators who have interpreted the current rule's use of the words 
``should'' and ``guidelines'' in Sec. 112.7 as an indication that 
compliance with the applicable provisions of the rule is optional. The 
rule used the words ``should'' and ``guidelines'' to provide 
flexibility for facilities with unique circumstances. Those 
circumstances might be such that mandated regulatory provisions would 
not be in accord with good engineering practice. Therefore, the rule 
gave facilities the opportunity to provide alternative methods that 
achieve equivalent environmental protection, or to show that the 
provisions were inapplicable based on specific circumstances.

[[Page 47052]]

    In 1991, we proposed to clarify that misunderstanding by generally 
substituting ``shall'' in place of ``should'' throughout the 
reorganized rule. In today's final rule, we have editorially changed 
``shall'' to ``must'' in furtherance of the Agency's ``plain language'' 
objectives. The ``shall'' to ``must'' is not a substantive change, but 
merely an editorial change. Nor will the change add to the information 
collection burden. We have always included requirements prefaced by 
``should'' in the information collection burden for the rule. We will 
continue to provide flexibility for an owner or operator who can 
explain his reasons for nonconformance with rule requirements, and can 
provide alternate measures from those specified in the rule, which 
achieve equivalent environmental protection. Section 112.7(a)(2) will 
provide such flexibility. In the exercise of our authority to inspect 
facilities and SPCC Plans, we reserve the right to find that such 
alternate methods do not provide equivalent environmental protection. 
In such cases, we would require the owner or operator of the facility 
to amend the SPCC Plan to provide equivalent environmental protection.
    Comments. Guidance. Several commenters supported the proposed 
change. One asked that discretionary provisions might be better placed 
in a separate guidance document. Several commenters were concerned that 
there are no guidance documents outlining equivalency as provided in 
proposed Sec. 112.7(a)(2) and that it may be impossible to prove 
equivalency to EPA.
    PE certification. Other commenters suggested that if the 
Professional Engineer (PE) certified the Plan as adequate for the 
facility, then the mandated requirements were unnecessary, as he would 
have determined that all appropriate equipment and planning is in 
place.
    Substantive change. Some commenters argued that the proposal was a 
substantive change, contrary to legislative intent, and that we failed 
to give opportunity for proper notice and comment, as required by the 
Administrative Procedure Act.
    Small production facilities. One commenter suggested that the 
clarification should not apply to small production facilities, defined 
as those with less than 3000 barrels of storage capacity, because those 
facilities would suffer severe hardship as a result.
    Response to comments. Guidance. EPA agrees with the comment that 
recommendations have no place in this rule because we do not wish to 
confuse the regulated public as to what is mandatory and what is 
discretionary. Instead, some recommendations are discussed in the 
preamble to this document, while others can be found in separate 
guidance documents or policy statements. When the rule or preamble is 
silent, or no published guidance or policy documents exist, we will 
generally use industry standards as guidance for rule compliance.
    PE certification. While we generally agree that certification by a 
PE should show that all necessary equipment and planning are in place, 
we reserve the right to make a determination that additional measures 
may be necessary to comply with the rule. EPA made it clear in proposed 
Sec. 112.3(d), which is finalized today, that a PE certification does 
not relieve the owner or operator of the duty to prepare and fully 
implement an SPCC Plan in accordance with the rule's requirements.
    Substantive change. We disagree that the change is either 
substantive or contrary to legislative intent. Section 311(j)(1)(C) of 
the Act authorizes the President and, through delegation, EPA, to 
establish ``procedures, methods, and equipment and other requirements 
for equipment to prevent discharges of oil and hazardous substances 
from vessels and from onshore facilities and offshore facilities, and 
to contain such discharges.'' That authority is ample to provide the 
basis for a mandatory SPCC rule, that is, a rule that establishes 
``requirements * * * to prevent discharges.''
    We also disagree that the proposed rule failed to provide proper 
notice and comment. The preamble to the 1991 proposed rule fully 
explained the rationale for the proposed change (56 FR 54620, October 
22, 1991), and numerous commenters responded. Furthermore, we have 
always interpreted and enforced our rules as mandatory requirements.
    EPA recognizes, however, that this clarification may result in 
certain owners or operators of regulated facilities recognizing for the 
first time that they have been and are subject to various provisions of 
part 112. Such owners and operators should, of course, take all 
necessary steps to come into compliance with this part as soon as 
possible. In exercising its prosecutorial discretion, the Agency always 
takes into account the good faith and efforts to comply of an owner or 
operator who has been in noncompliance with applicable laws and 
regulations when deciding whether or not to take an enforcement action.
    Small production facilities. We disagree that the ``should'' to 
``must'' change will generally pose a severe hardship for small 
production facilities. As noted above, EPA has always interpreted the 
``shoulds'' as ``musts.'' Further, when a particular requirement is not 
feasible for a particular facility, under Sec. 112.7(a)(2) that 
facility may explain the reasons for nonconformance with the 
requirement, and provide alternate measures that achieve equivalent 
environmental protection.

D. Professional Engineers (PEs)

    Background. In the preamble to the 1991 proposal (56 FR 54618), EPA 
posed several questions to commenters regarding how PEs could help to 
implement the SPCC Plan. An owner or operator of a facility is required 
to secure the certification of a PE on an SPCC Plan, and on technical 
amendments to the Plan. By means of this certification, the PE attests 
that the Plan or the amendment has been prepared in accordance with 
good engineering practice.
1. State Registration
    Background. We solicited comments on the advantages and 
disadvantages associated with the PE being registered in the State in 
which the facility is located. EPA noted that ``a requirement that a PE 
be licensed in the State in which the facility is located would allow 
the State licensing board to more easily address the actions of the PE 
under its jurisdiction, and that the PE may have greater familiarity 
with the State and local requirements related to the facility under 
review.'' 56 FR 54619.
    Comments. Favorable comments. Several commenters supported a 
requirement that the PE be registered in the State in which the 
facility is located. The rationales often expressed were that: (1) 
Letting any PE certify any SPCC Plan effectively removed the PE from 
the supervision of the State board; and, (2) familiarity with the State 
and local requirements related to the facility as well as the State 
itself are essential for viable SPCC Plans. One commenter suggested 
that when an out-of-State PE prepares the Plan, the Plan should bear 
the seal of the PE who prepared the Plan along with the seal of a PE 
registered in the State in which the facility is located, assuring that 
the proposed Plan conforms to any additional State requirements.
    Opposing comments. Opposing commenters argued that: (1) A State 
licensing board will address the actions of an engineer regardless of 
the engineer's location when he applies his seal; (2) suggestions that 
the potential liability of the engineer might be limited if the 
engineer holds an out-of-State license are specious; (3) SPCC Plan

[[Page 47053]]

preparation is a Federal activity, therefore, it is unnecessary to have 
State registration; and, (4) such a requirement would reduce the 
available pool of qualified PEs. One commenter volunteered that the 
proposal was ``superfluous'' because the practice of engineering in a 
State without being professionally registered in that State is unlawful 
in most States.
    Response to comments. We agree with commenters that it is 
unnecessary that the PE be registered or licensed in the State in which 
the facility is located because any abuses will be corrected by the 
licensing jurisdiction. We also agree that such a requirement might 
unnecessarily reduce the availability of PEs and increase the cost of 
certification without any tangible benefits. The professional liability 
of a PE would likely be unaffected by the place of his registration. 
When State law precludes a PE from applying his seal if he is not 
licensed in that State, the question of State registration becomes 
moot. However, that is not the case in every State.
    We also disagree that if a PE is not licensed in the State, he will 
be unfamiliar with State and local requirements for the facility. Any 
PE may become familiar with both Federal and State and local 
requirements for a facility. Therefore, to require that the PE be 
registered in the State in which the facility is located would impose 
unnecessary financial burdens on the facility and would challenge the 
integrity of the PE. Such a requirement would also reduce the pool of 
PEs available for facilities.
2. PEs Employed by the Facility
    Background. EPA asked whether the rule should specify that the PE 
not be an employee of the facility or have any other direct financial 
interest in the facility. This request for comment had its origin in a 
U.S. General Accounting Office (GAO) report issued on February 22, 
1989, ``Inland Oil Spills: Stronger Regulation and Enforcement Needed 
to Avoid Future Incidents'' (GAO/RCED-89-65).'' The GAO report 
recommended that EPA evaluate the advantages and disadvantages of 
requiring facilities to obtain certifications from independent 
engineers. EPA noted that ``not having the PE otherwise associated with 
the facility may avoid any potential conflicts of interest or 
appearance of conflicts of interest that could arise from allowing an 
employee of a regulated party to certify a SPCC Plan.'' 56 FR 54619. On 
the other hand, for both the issues of whether to require State 
registration and whether to allow PEs employed by the facility to 
certify SPCC Plans, EPA noted that some organizations objected to the 
proposals as ``challenging the integrity of professional engineers.'' 
56 FR 54619. We also pointed out that some professional organizations 
believe that such requirements ``would impose substantial costs without 
enhancing the integrity of the certification process.'' 56 FR 54619.
    Comments. Favorable comments. Several commenters supported a 
requirement that the PE not be an employee of the facility or not have 
a direct financial interest in it. The rationales most often asserted 
were: (1) A Plan would better satisfy regulatory objectives and better 
serve the public; (2) the Plan would be less subject to compromise by 
other factors; (3) Plan certification is less likely to be a coerced or 
superficial effort, and undue economic and moral pressures would be 
avoided; (4) more cooperative efforts among regulatory bodies, 
engineers, and the facility would be possible; (5) more economic and 
effective Plan development is assured; and, (6) more competent and more 
professional Plan development is guaranteed.
    Opposing comments. Opposing commenters asserted that: (1) Such a 
proposal would limit the availability of PEs, leading to delays in Plan 
certification; (2) administrative action to correct abuses would be a 
better approach; and, (3) such an approach insults the ethical 
integrity of PE. One commenter suggested that ``to suppose a facility 
employee would break the law and jeopardize his license to practice his 
profession and do it more willingly than an ``independent'' engineer 
has no basis in fact'; (4) an in-house PE may be the person most 
familiar with the facility; (5) the proposal would place an undue and 
unnecessary financial burden on the owner or operator of a facility by 
forcing him to hire an outside engineer; and, (6) it is uncertain 
whether an independent PE can afford the insurance necessary to certify 
his work given that the liability incurred might run into the millions 
of dollars.
    Compromise position. One commenter suggested that a compromise 
position might be that the PE who certifies the Plan would be required 
to disclose in the Plan certification his relationship to the facility 
owner, the facility improvements owner, and the facility landowner.
    Response to comments. We agree that a proposal to restrict 
certification by a PE employed by a facility or having a financial 
interest in it would limit the availability of PEs, possibly leading to 
delays in Plan certification. Therefore, we will not adopt it. Nor do 
we favor the proposal to require the PE to disclose his relationship to 
the facility owner, the facility improvements owner, or the facility 
landowner. Such disclosure would add no environmental protection to the 
SPCC certification process. Administrative action to correct abuses 
would be a better approach. We believe that most PEs, whether 
independent or employees of a facility, being professionals, will 
uphold the integrity of their profession and only certify Plans that 
meet regulatory requirements. We also agree that an in-house PE may be 
the person most familiar with the facility. EPA believes that a 
restriction of in-house PE certification might place an undue and 
unnecessary financial burden on owners or operators of facilities by 
forcing them to hire an outside engineer.
3. Completion of Testing
    Background. The Agency proposed that the PE must attest that 
required testing has been completed and the Plan meets the requirements 
of the regulation for the facility. This proposal was advanced to 
``promote the Agency's intent in the original promulgation of 
Sec. 112.3(d) that SPCC Plans be certified by a Registered Professional 
Engineer exercising independent judgment.'' 56 FR 54619. These new 
requirements were to be met when a new Plan is prepared after 
promulgation of the rule, or when an existing Plan is amended, under 
Sec. 112.5.
    Comments. Favorable comments. One commenter supported a requirement 
that the PE attest to the completion of testing and that the Plan meets 
regulatory requirements.
    Opposing comments. Some opposing commenters believed that the PE 
should ``enumerate all the inspections and tests that have been 
completed, plus those that should be completed before the facility 
commences operations and those that should be undertaken periodically 
after it commences operations.'' Others believed that completion of 
required testing is the responsibility of the operator and not the PE. 
Another commenter believed such a requirement would be impossible, 
because ``required testing may take up to a year to complete.''
    Response to comments. EPA agrees that the PE is not responsible for 
certifying that all required testing has been completed. Rather, such 
responsibility belongs to the owner or operator of the facility. 
Testing may be ongoing long after the Plan is certified. The PE is 
responsible for certifying that the Plan is adequate and meets all 
regulatory requirements, including enumeration of all tests that have 
been

[[Page 47054]]

completed, plus those that should be completed before the facility 
commences operations and those that should be undertaken periodically 
after it commences operations. Therefore, we are changing the proposed 
requirement to a requirement in which the PE attests that the 
procedures for required inspections and testing have been established, 
and the Plan is adequate for the facility. See the discussion of 
Sec. 112.3(d), below.
4. Site Visits
    Background. We stated that EPA ``believes the current regulatory 
language (e.g., requiring the engineer to examine the facility) clearly 
requires the certifying Engineer to visit the facility prior to 
certifying the SPCC Plan.'' We added that the proposed change 
``clarifies this requirement by specifying that the Professional 
Engineer must be physically present to examine the facility.'' 56 FR 
54619.
    Comments. Favorable comments. Many commenters favored the 
requirement that the PE make a site visit prior to certifying a Plan. 
Those commenters called such a visit ``absolutely necessary.'' Some 
argued that a generic plan prepared by an engineer who has never seen 
the facility is unacceptable.
    Opposing comments. Opposing commenters asserted that such visits 
only involve additional costs and duplication of efforts without any 
tangible benefits. Many opposing commenters argued that customary 
engineering practice includes the use of engineering technicians, 
technologists, graduate engineers, and others to prepare preliminary 
reports, studies, and evaluations. After preparation of these 
documents, the PE would then perform a careful review of all pertinent 
material and then sign and seal the appropriate plans and drawings. 
Other commenters argued that such a requirement would be impractical, 
particularly at electrical substations, due to their large number.
    Particular cases. One commenter urged that small facilities be 
exempted from the site visit requirement where ``a determination is 
made that sufficient documentation of site characteristics is available 
for plan certification.'' That commenter noted that in many instances 
sufficient information is available from topographic maps, aerial 
photographs, soil surveys, hydrologic studies, engineering and 
construction reports, and local operating personnel to eliminate the 
need for site visits prior to certification. Another commenter urged an 
exemption for temporary storage facilities because given their 
emergency nature, certification is impractical. One commenter asked for 
clarification that the certification of an existing Plan is sufficient 
until the Plan update is required. Another suggested that the rule 
should only require that the PE be familiar with the operation and 
design of the type of facility, and that he would have visited and 
examined one or more facilities of this type.
    Response to comments. In general. EPA agrees that the rule should 
not necessarily require a site visit by a certifying PE, but we believe 
that a site visit should occur before the PE certifies the Plan. We 
have modified proposed Sec. 112.3(d)(ii) to reflect this position. The 
PE's agent may perform the visit. We agree that customary engineering 
practice allows someone under the PE's employ such as an engineering 
technician, technologist, graduate engineer, or other qualified person 
to prepare preliminary reports, studies, and evaluations after visiting 
the site. Then the PE could legitimately certify the Plan. 
Nevertheless, in all cases the PE must ensure that his certification 
represents an exercise of good engineering judgment. If that requires a 
personal site visit, the PE must visit the facility himself before 
certifying the Plan.
    Particular cases. EPA agrees that a PE site visit requirement might 
be impractical at electrical substations, due to their large number. 
However, the PE need not go. One of his agents may go, and he may 
review the agent's work. We disagree with commenters who believe that a 
site visit is unnecessary at small facilities and temporary storage 
facilities. Site visits are necessary for those facilities to ensure 
Plan adequacy and to prevent discharges.
    EPA has interpreted the current rule language to contain a 
requirement that the PE examine the facility. Because of the 
uncertainty concerning the nature of this requirement, however, we will 
not require documentation of a site visit by a PE or his agent until 
after the effective date of this rule. We disagree that the rule should 
only require that the PE be familiar with the operation and design of 
the type of facility. We also disagree that merely because the PE has 
visited and examined one or more facilities of a particular type that 
no site visit is necessary. A facility may have individual 
characteristics that differ from those of its type in general, and a 
site visit by a PE or agent may be necessary to detect those 
characteristics and accommodate them in the Plan. Such individual 
characteristics include geographic conditions, possible flow paths, 
facility design and construction, type of containers, product stored, 
particular equipment, and the integrity of containment at the facility. 
Therefore, even if a PE has inspected many facilities of a particular 
type, that fact does not eliminate the need for a site visit at each 
facility. After the site visit, the PE will have to devise appropriate 
inspection and testing standards based on the facility's unique 
characteristics.

E. Electrical Facilities and Other Operational Users of Oil

    Background. In 1991, we proposed that certain facilities having 
equipment containing oil that is used for operational purposes, such as 
electrical transformers, would not have to comply with secondary 
containment requirements and certain other provisions proposed in 
Secs. 112.8(c) and 112.9(d) because such facilities are not bulk 
storage facilities. EPA asked for comment on this and also asked 
commenters to identify other possible operational uses of oil, other 
than electrical transformers, that may not currently use secondary 
containment as a common industry practice and that should not be 
subject to bulk storage provisions. 56 FR 54623.
    Comments. Use of oil. Numerous commenters, especially in the 
electric utility industry, asserted that EPA has no jurisdiction to 
regulate the operational use of oil generally, or specifically in 
electrical transformers, substations, and other equipment. Some 
manufacturers of other products agreed. They argued that the 
legislative history of the Act showed no Congressional intent for such 
regulation. However, many commenters asked EPA specifically to clarify 
this jurisdictional issue.
    Response to comments. Use of oil. We disagree that operational 
equipment is not subject to the SPCC rule. We have amended 
Sec. 112.1(b) to clarify that using oil, for example operationally, may 
subject a facility to SPCC jurisdiction as long as the other 
applicability criteria apply, for example, oil storage capacity, or 
location. Such a facility might reasonably be expected to discharge oil 
as described in Sec. 112.1(b). Therefore, the prevention of discharges 
from such facility falls within the scope of the statute.
    However, we have distinguished the bulk storage of oil from the 
operational use of oil. We define ``bulk storage container'' in the 
final rule to mean any container used to store oil. The storage of oil 
may be prior to use, while being used, or prior to further distribution 
in commerce. For clarity, we have specifically excluded oil-filled 
electrical, operating, or manufacturing equipment from the definition.

[[Page 47055]]

    Facilities that use oil operationally include electrical 
substations, facilities containing electrical transformers, and certain 
hydraulic or manufacturing equipment. The requirements for bulk storage 
containers may not always apply to these facilities since the primary 
purpose of this equipment is not the storage of oil in bulk. Facilities 
with equipment containing oil for ancillary purposes are not required 
to provide the secondary containment required for bulk storage 
facilities (Sec. 112.8(c)) and onshore production facilities 
(Sec. 112.9(c)), nor implement the other provisions of Sec. 112.8(c) or 
Sec. 112.9(c). Oil-filled equipment must meet other SPCC requirements, 
for example, the general requirements of this part, including 
Sec. 112.7(c), to provide appropriate containment and/or diversionary 
structures to prevent discharged oil from reaching a navigable 
watercourse. The general requirement for secondary containment, which 
can be provided by various means including drainage systems, spill 
diversion ponds, etc., will provide for safety and also meet the needs 
of section 311(j)(1)(C) of the CWA. EPA will continue to evaluate 
whether the general secondary containment requirements found in 
Sec. 112.7(c) should be modified for small electrical and other types 
of equipment which use oil for operating purposes. We intend to publish 
a notice asking for additional data and comment on this issue.
    In addition, a facility may deviate from most SPCC requirements, if 
the owner or operator explains his reasons for nonconformance and 
provides equivalent environmental protection by some other means. See 
Sec. 112.7(a)(2). See also Sec. 112.7(d).

F. Discretionary Provisions

    Background. In the preamble to the 1991 proposal (at 56 FR 54616), 
we asked for comments as to whether the provisions proposed as 
recommendations in rule text should be made requirements. We then noted 
that we were ``particularly interested in receiving comments and 
information on the advisability of establishing'' certain provisions as 
``requirements for large facilities, but as recommendations for small 
facilities.'' These provisions were: (1) Proposed Sec. 112.8(d)(4)--
``that facilities have all buried piping tested for integrity and leaks 
annually or have buried piping monitored monthly in accordance with the 
provisions of 40 CFR part 280.'' We also recommended that records of 
testing or monitoring be kept for five years.; and, (2) proposed 
Sec. 112.8(d)(5)--``that facilities post vehicle weight restrictions to 
prevent damage to underground piping.'' Individual proposals will be 
discussed under their relevant sections in this preamble. Large 
facilities were defined for this purpose as facilities with more than 
42,000 gallons of SPCC-regulated storage capacity. Conversely, we asked 
whether such provisions should be discretionary for smaller facilities. 
The rationale expressed in the question was EPA believes that ``larger 
volumes of oil stored at a facility increase the chances of a spill 
occurring, and that spills from large-capacity facilities may be 
greater in magnitude than those from smaller facilities, thus posing a 
greater potential threat to the waters of the United States.''
    EPA also requested comments on two other practices it proposed as 
recommendations, but did not include in rule text. Those practices 
were: (1) ``That owners and operators of facilities affix a signed and 
dated statement to the SPCC Plan indicating that the revision has taken 
place and whether or not amendment of the Plan is required;'' and, (2) 
``That owners and operators of onshore facilities other than production 
facilities state the design capabilities of their drainage system in 
the SPCC Plan if the system is relied upon to control spills or 
leaks.'' Concerning the first practice, see also the discussion under 
Sec. 112.5(b) of today's rule. The rationale for these recommendations 
was that ``these provisions may not for all facilities achieve the 
standard of provisions based on good engineering practice, which is the 
basic standard of the regulation. EPA, however believes that 
implementation of these provisions at most facilities would contribute 
to the facilities' overall effort to prevent oil discharge and to 
mitigate those spills that may occur.'' The Agency also asked whether 
some of these provisions should be mandatory.
    Comments. Large or small facility regulation, in general. EPA 
received a number of comments on this issue, some directed towards 
regulation of larger and smaller facilities in general, and others 
toward specific provisions proposed. Some commenters believed that 
larger facilities could better bear the costs of regulation than 
smaller facilities, some of which were financially marginal and might 
go out of business as a result of environmental regulation.
    Storage capacity level. Commenters suggested different storage 
capacity levels at which to differentiate large from small facilities. 
Those suggestions ranged from 10,000 to 100,000 gallons in storage 
capacity. Many, however, supported the 42,000-gallon level.
    Other factors. One commenter suggested that other factors such as 
proximity to navigable waters or environmentally sensitive areas, as 
well as the use of good engineering practices should be considered in 
the regulation of facilities. The commenter argues that these factors 
might avoid overburdening a large facility with a low potential for 
impact on a navigable water or exempting a small facility with a high 
potential for impact on a navigable water.
    Discretionary provisions. Favorable commenters. Numerous commenters 
favored discretionary provisions in the interest of maintaining 
flexibility in the program, noting that what may be appropriate for one 
facility may not be appropriate for another. Some commenters favored 
applying discretionary provisions to small facilities only, leaving the 
provisions as requirements for larger facilities.
    Discretionary provisions. Opposing commenters. Some commenters 
argued that discretionary provisions are inappropriate in a rule as a 
matter of principle because they complicate mandatory rule documents 
and enforcement, and they confuse the regulated community. Yet others 
urged that such provisions were unnecessary in any case because they 
believe that no risks exist for which the discretionary provisions were 
proposed.
    Response to comments. We will discuss specific comments under the 
discussion of specific sections. See section IV.G of today's preamble 
for a discussion of the ``Design Capabilities of Drainage Systems, 
other than Production Facilities.'' Our general discussion follows.
    Large or small facility regulation, in general. We have decided not 
to regulate facilities differently based merely on storage capacity, 
provided that the capacity is above the regulatory threshold of over 
1,320 gallons. This decision is based on environmental reasons. Small 
discharges of oil that reach the environment can cause significant 
harm. Sensitive environments, such as areas with diverse and/or 
protected flora and fauna, are vulnerable to small spills. EPA noted in 
a recent denial of a petition for rulemaking: ``Small spills of 
petroleum and vegetable oils and animal fats can cause significant 
environmental damage. Real-world examples of oil spills demonstrate 
that spills of petroleum oils and vegetable oils and animal fats do 
occur and produce deleterious environmental effects. In some cases, 
small spills of vegetable oils can produce more environmental harm than 
numerous large spills of petroleum

[[Page 47056]]

oils.'' 62 FR 54508, 54530, October 20, 1997. Describing the outcome of 
one small spill of 400 gallons of rapeseed oil into Vancouver Harbor, 
we noted that `` * * * 88 oiled birds of 14 species were recovered 
after the spill, and half of them were dead. Oiled birds usually are 
not recovered for 3 days after a spill, when they become weakened 
enough to be captured. Of the survivors, half died during treatment. 
The number of casualties from the rapeseed oil spills was probably 
higher than the number of birds recovered, because heavily oiled birds 
sink and dying or dead birds are captured quickly by raptors and 
scavengers.'' 62 FR 54525.
    A small discharge may also cause harm to human health or life 
through threat of fire or explosion, or short-or long-term exposure to 
toxic components.
    Other factors. Finally, EPA notes that the rule affords flexibility 
to an owner or operator of a facility to design a Plan based on his 
specific circumstances. It allows him to choose methods that best 
protect the environment. It permits deviations from most of the 
mandatory substantive requirements of the rule when the facility owner 
or operator can demonstrate a reason for nonconformance, and can 
provide equivalent environmental protection by other means. 
Consequently, both small and large facilities have the opportunity to 
reduce costs by alternative methods if they can maintain environmental 
protection. Because smaller facilities may require less complex plans 
than larger ones, their costs may be less.
    Discretionary provisions. We agree that discretionary provisions 
have no place in this rule because we do not wish to confuse the 
regulated community and complicate enforcement by blurring what is 
mandatory and what is discretionary. We will provide guidance or policy 
statements on various issues, as necessary, that will incorporate some 
or all of these recommendations. In the absence of such guidance or 
policy statements, you should look to current industry standards for 
guidance on technical issues. See also our discussion of industry 
standards and good engineering practice under section IV.K of today's 
preamble and under Sec. 112.3(d) in section V of today's preamble.

G. Design Capabilities of Drainage Systems, Other than Production 
Facilities

    Background. In the 1991 preamble, we asked for comments on, but did 
not propose, a provision that owners or operators of onshore facilities 
other than production facilities describe the design capabilities of 
their drainage systems in the SPCC Plan if the system is relied upon to 
control spills or leaks. 56 FR 54616, October 22, 1991. See also 
section IV.F of today's preamble for a discussion of other 
``Discretionary Provisions.''
    Comments. Favorable comments. Commenters favoring such a 
requirement asserted that such a description would help identify all 
paths of escape for discharges at a facility, assess the spill 
retention capacity of the facility's containment system, and identify 
the risks to the public of a discharge. Those commenters generally 
believed that the Professional Engineer should develop the description 
for the Plan.
    Opposing comments. Commenters opposing making the recommendation a 
requirement argued that it was unnecessary because the rules already 
require certain descriptions of design capabilities of drainage 
systems. They asserted that such a requirement would be redundant in 
that if a drainage system is relied upon to control spills or leaks, 
then it must have design capabilities to control such spills or leaks.
    Response to comments. The question of description of the design 
capabilities of drainage systems for onshore facilities other than 
production facilities is adequately covered by rules pertaining to 
drainage. See, for example, Secs. 112.7(a)(3) and (4), 112.7(b), 
112.8(b), and 112.10(c). Therefore, we will not promulgate any 
additional requirements on this subject. These provisions generally 
require that a facility owner or operator design the facility drainage 
system to prevent discharges, or if prevention fails, to contain the 
discharge within the facility.

H. Compliance Costs

    Background. We provided an extensive discussion of the costs and 
benefits of the proposed 1991 rule. 56 FR 54628-54629, October 22, 
1991. We requested comments in the 1991 preamble concerning the new 
compliance costs associated with the proposed rule.
    Comments. EPA received numerous comments on this issue. The 
overwhelming majority of commenters asserted that the proposed rule 
would impose costs that few could bear. Many argued that such costs 
were unnecessary or should be applied to large facilities only.
    Response to comments. EPA considered cost factors in finalizing the 
requirements in this rule. We believe that facilities in compliance 
with the current rule will incur minimal additional cost due to the 
revisions in this rule. Many of the provisions we proposed in 1991 that 
commenters believed were too costly were not finalized in this rule. In 
addition, in today's rule, we have provided flexibility in several 
ways. Many of the provisions we proposed in 1991 that commenters 
believed were too costly were not finalized in this rule. In addition, 
in the deviation provision, Sec. 112.7(a)(2), we permit you to 
substitute alternate measures that provide equivalent environmental 
protection if you can explain a reason for nonconformance with the 
prescribed requirement. We also rely on the use of industry standards 
in many provisions, rather than mandating any particular procedure, or 
any particular monitoring or inspection schedule. We assume that most 
facilities follow industry standards, and therefore will not incur 
additional costs for many provisions where they do. We recognize, 
however, that to the extent any facility does not follow current 
industry standards, it might incur additional costs. Furthermore, we 
are finalizing other provisions in this rule which will reduce burden 
in other ways and will exempt certain facilities from having to prepare 
an SPCC or FRP Plan. EPA has also prepared an assessment of the costs 
of rule compliance, which is discussed in part VI.F (Regulatory 
Flexibility Act) of this preamble, and we have included the specific 
comments related to costs and our responses in relevant sections of 
this preamble.

I. Contingency Planning and Notification

    Background. We requested comments in the 1991 preamble on spill 
contingency planning needs (at 56 FR 54615) and on proposed facility 
notification requirements (at 56 FR 54614). You will find a detailed 
discussion of contingency requirements and facility notification 
requirements (Sec. 112.7(d) and proposed Sec. 112.1(e)) in Section V of 
today's preamble. On those subjects, we briefly summarize the comments 
and our responses below.
    Comments. Contingency planning. Many commenters supported the 1991 
proposal. Opposing commenters suggested that such planning should be 
discretionary because not all facilities need such planning, or that 
facilities be allowed to use contingency plans prepared for other 
purposes. Others thought the proposal was premature as we had not at 
the time finalized response planning requirements in Sec. 112.20. Some 
said that contingency planning was not practicable because

[[Page 47057]]

the costs are too high, but these commenters did not provide specific 
cost estimates.
    Notification. A number of commenters favored the proposal, 
including some industry commenters. Most industry commenters opposed 
the proposal either in part or in its entirety. Commenters who opposed 
the proposal in its entirety asserted that it was unnecessary, largely 
because they believed the information sought might be better obtained 
from other sources, such as State sources or SARA Title III reports.
    Response to comments. Contingency planning. Contingency planning is 
necessary whenever you determine that a secondary containment system 
for any part of the facility that might be the cause of a discharge as 
described in Sec. 112.1(b) is not practicable. This requirement applies 
whether the facility is manned or unmanned, urban or rural, and for 
large and small facilities. Because we have not finalized either the 
1991 or 1993 contingency plan proposals, there are no new costs. We 
note that we finalized response planning requirements in 1994. 
Contingency plans prepared for other purposes are acceptable for SPCC 
purposes if they satisfy all SPCC requirements.
    Notification. Withdrawal of proposal. We have decided to withdraw 
the proposed facility notification requirement because we are still 
considering issues associated with establishing a paper versus 
electronic notification system, including issues related to providing 
electronic signatures on the notification. Should the Agency in the 
future decide to move forward with a facility notification requirement, 
we will repropose such requirement.

J. Reproposal

    Background: In the 1997 proposal, we stated that we would finalize 
the 1991 and 1993 proposals without seeking additional comments on 
those proposals.
    Comments: Some commenters suggested that we repropose the 1991 
proposal ``so that the public can view the proposed changes in a 
comprehensive manner.'' Other commenters suggested that the time that 
has elapsed, the changes in operational procedures of the oil and gas 
industry which have improved the degree of environmental protection, 
and the new information EPA obtained from its tank survey, justified 
reproposal. Others cited changes in oil industry personnel as a reason 
to repropose the rule. Some commenters believed that the implementation 
of the Facility Response Plan (FRP) rule alone requires us to solicit 
additional comments concerning the SPCC proposals.
    Response: Additional comments or reproposal. We believe it is 
unnecessary to repropose the 1991 and 1993 proposals because of mere 
passage of time. We received numerous comments on every side of most 
issues. In developing this final rule, we have considered changes that 
have taken place in the oil industry, industry standards, and 
regulations that may affect the SPCC rule. We have also considered 
changes in the various industries which comprise the universe of SPCC 
facilities which have occurred since our original proposals. We 
encourage the use of industry standards to implement the rule, without 
incorporating any particular standard into the rule, thereby averting 
possible obsolescence of those standards. We used the results of our 
1995 SPCC facility survey to develop our 1997 proposed rule. These 
results are also part of the administrative record for this rulemaking. 
We considered all the comments we received in 1997, even if they dealt 
with issues proposed in 1991 or 1993. We have also considered and 
responded to all of the comments received in 1991 and 1993 in their 
respective Comment Response Documents or in the preamble to today's 
final rule.
    Personnel changes. In developing this final rule, as noted above, 
we have considered changes that have taken place in the oil industry, 
industry standards, and regulations that may affect the SPCC rule. For 
the past 26 years, owners and operators of regulated facilities have 
been responsible for training their personnel in applicable 
regulations, such as 40 CFR part 112. Such responsibility is in effect 
now, and will continue under the revised rule. New companies and new 
personnel of those companies are on notice as to applicable rules and 
proposals. They have also had the opportunity to comment on the 1997 
proposal. Furthermore, we have considered cost implications for all 
three proposals which we are finalizing today.
    Response plan requirements. We have no plans to require SPCC 
facilities for which secondary containment is not practicable to 
develop response plans. However, we have withdrawn Sec. 112.7(d) as 
proposed in 1993. Only a contingency plan following the provisions of 
40 CFR part 109 and compliance with other provisions of Sec. 112.7(d) 
is necessary when secondary containment is impracticable. Only onshore 
facilities that meet the criteria of substantial harm and/or 
significant and substantial harm facilities need to comply with the FRP 
requirements in 40 CFR 112.20-21.

K. Industry Standards

    Throughout the rule we generally allow for the application of 
industry standards where the standards are both specific and objective, 
and their application may reduce the risk of discharges to and impacts 
to the environment. We recognize that as technology advances, specific 
standards change. By referencing industry standards throughout the 
preamble, we anticipate that the underlying requirements of the rule 
itself will change as new technology comes into use without the need 
for further amendments. We believe that industry standards today 
represent good engineering practice and generally are environmentally 
protective. However, as under the current rule, if an industry standard 
changes in a way that would increase the risk of a discharge as 
described in Sec. 112.1(b), EPA will apply and enforce standards and 
practices that protect the environment, rather than the less protective 
industry standard.
    Under the terms of this rule, when there is no specific and 
objective industry standard that applies to your facility (for example, 
whether there is no standard or a standard that uses the terms ``as 
appropriate,'' ``often,'' ``periodically,'' and so forth), you should 
instead follow any specific and objective manufacturer's instructions 
for the use and maintenance or installation of the equipment, 
appurtenance, or container. If there is neither a specific and 
objective industry standard nor a specific and objective manufacturer's 
instruction that applies, then it is the duty of the PE under 
Sec. 112.3(d) to establish such specific and objective standards for 
the facility and, under Sec. 112.3(d), he must document these standards 
in the Plan. If the PE requires the use of a specific standard for 
implementation of the Plan, the owner or operator must also reference 
that standard in the Plan.
    Throughout this preamble, we list industry standards that may 
assist an owner or operator to comply with particular rules. The list 
of those standards is merely for your information. They may or may not 
apply to your facility, but we believe that their inclusion is helpful 
because they generally are applicable to the topic referenced. The 
decision in every case as to the applicability of any industry standard 
will be one for the PE.
    For your convenience, we are including a list of organizations 
below

[[Page 47058]]

that may be helpful in the identification and explanation of industry 
standards.

----------------------------------------------------------------------------------------------------------------
               Name                         Address                Phone            Web Site/E-mail
----------------------------------------------------------------------------------------------------------------
American National Standards        11 West 42nd Street, New   212-642-4900............  www.ansi.org
 Institute (ANSI).                  York, NY 10036.           212-398-0023 fax........  [email protected]
American Petroleum Institute       1220 L Street, NW          202-682-8000............  www.api.org
 (API).                             Washington, DC 20005.     202-682-8232 fax........  [email protected]
                                                                                        [email protected]
American Society of Mechanical     Three Park Avenue New      800-843-2763............  www.asme.org
 Engineers (ASME).                  York, NY 10016-5990.      973-882-1717 fax........  [email protected]
American Society for               PO Box 28518, 1711         800-222-2768............  www.asnt.org
 Nondestructive Testing (ASNT).     Arlingate Lane Columbus,  614-274-6899 fax........
                                    OH 43228-0518.
American Society for Testing and   100 Barr Harbor Drive,     610-832-9585............  www.astm.org
 Materials (ASTM).                  West Conshohocken, PA     610-832-9555 fax........  [email protected].
                                    19428-2959.
Building Officials and Code        4051 West Flossmoor Road   708-799-2300............  www.bocai.org
 Administrators (BOCA)              Country Club Hills, IL    708-799-4981 fax........  [email protected].
 International.                     60478.
International Code Council (ICC).  5203 Leesburg Pike, Suite  703-931-4533............  www.intlcode.org
                                    708 Falls Church, VA      703-379-1546 fax........  [email protected].
                                    22041.
International Conference of        5360 Workman Mill Road     888-699-0541............  www.icbo.org
 Building Officials (ICBO).         Whittier, CA 90601-2298.  888-329-4220 fax........
International Fire Code Institute  5360 Workman Mill Road     562-699-0124............  www.ifci.org
 (IFCI).                            Whittier, CA 90601-2298.  562-699-8031 fax........  [email protected]
Manufacturers Standardization      127 Park Street, N.E.      703-281-6613............  www.mss-hq.com
 Society of The Valve and           Vienna, VA 22180-4602.    703-281-6671 fax........  hg.com">info@mss-hg.com
 Fittings Industry Inc. (MSS).
National Association of Corrosion  1440 South Creek Drive     281-228-6200............  www.nace.org
 Engineers (NACE).                  Houston, TX 77084.        281-228-6300 fax........
National Fire Protection           1 Batterymarch Park PO     617-770-3000............  www.nfpa.org
 Association (NFPA).                Box 9101 Quincy, MA       617-770-0700 fax........  [email protected]
                                    02269-9101.
Petroleum Equipment Institute      P.O. Box 2380 Tulsa, OK    918-494-9696............  www.pei.org
 (PEI).                             74101-2380.               918-491-9895 fax........  [email protected].
Southern Building Code Congress    900 Montclair Road         205-591-1853............  www.sbcci.org
 International (SBCCI).             Birmingham, AL 35213-     205-591-0775 fax........  [email protected]
                                    1206.
Southwest Research Institute       P.O. Box Drawer 28510 San  210-684-5111............  www.swri.org
 (SwRI).                            Antonio, TX 78228-0510.                             [email protected]
Steel Tank Institute (STI).......  570 Oakwood Road Lake      847-438-8265............  www.steeltank.com
                                    Zurich, IL 60047.         847-438-8766 fax........  [email protected]
Underwriters Laboratories (UL)...  333 Pfingsten Road         847-272-8800............  www.ul.com
                                    Northbrook, IL 60062-     847-272-8129 fax........  [email protected]
                                    2096.
Western Fire Chiefs Association    300 N. Main St. www.wfca.com
 (WFCA).                            i>25 Fallbrook, CA 92028. 760-723-6912 fax........  [email protected]
----------------------------------------------------------------------------------------------------------------

V. Section by Section Analysis (Includes: Background, Comments, and 
Response to Comments)

Subpart A--Applicability, definitions, and general requirements for all 
facilities

    Background. In the reformatted rule, subpart A defines the 
applicability of part 112, provides definitions applicable to all 
subparts, and prescribes general requirements that are applicable to 
all facilities subject to part 112.

Section 112.1(a)(1)--General Applicability of the Rule

    Background. We have redesignated Sec. 112.1(a) as Sec. 112.1(a)(1) 
due to the addition of a new paragraph (a)(2). In 1991, we proposed 
changes in Sec. 112.1(a) to conform to the 1977 CWA amendments. Those 
amendments extended the geographic scope of EPA's authority under CWA 
section 311. Formerly the geographic scope of the rule extended only to 
navigable waters of the United States and adjoining shorelines. The 
final rule extends the geographic scope of EPA's authority beyond 
discharges to navigable waters and adjoining shorelines to include a 
discharge into or upon the waters of the contiguous zone, or in 
connection with activities under the Outer Continental Shelf Lands Act 
or the Deepwater Port Act of 1974, or that may affect natural resources 
belonging to, appertaining to, or under the exclusive management 
authority of the United States (including resources under the Magnuson 
Fishery

[[Page 47059]]

Conservation and Management Act). Hereinafter, a discharge as described 
above in quantities that may be harmful is also referred to as ``a 
discharge as described in Sec. 112.1(b).''
    Comments. Geographic scope of rule. One commenter wrote to support 
the geographic extension of the rule, noting that the extended 
definition ``will allow for more clarity in determining which 
facilities are subject to SPCC requirements.''
    Natural resources. Another commenter was concerned that the 
extension of the rule to facilities with the potential to affect 
natural resources ``would bring under the scope of 40 CFR 112 a 
significant number of operating facilities which did not previously 
require SPCC plans.'' Still another commenter proposed limiting the 
scope of natural resource jurisdiction under the rule to resources 
under the Magnuson Fishery and Conservation Act to avoid ``another 
unnecessary workload on the judicial system over the years.''
    Response to comments. Geographic scope of rule. EPA believes that 
the geographic extension of the rule to agree with statutory amendments 
is the proper course, and has finalized the rule as proposed.
    Natural resources. Limiting the scope of natural resource 
jurisdiction under the rule to natural resources under the Magnuson 
Fishery Conservation and Management Act would be inconsistent with this 
statutory language. We also believe that few, if any new facilities, 
will be subject to the rule because of its extension to facilities with 
the potential to affect certain natural resources. We believe that most 
affected facilities are either already subject to the rule, or not 
subject to our jurisdiction due to a Memorandum of Understanding 
between EPA, the U.S. Department of Transportation (DOT), and the U.S. 
Department of the Interior (DOI), which assigns jurisdiction over most 
of those facilities to DOT or DOI. See 40 CFR part 112, Appendix B.
    Editorial changes and clarifications. While revisions to the rule 
published today are not retroactive, any violation of the current rule 
which occurs before the effective date of today's rule is subject to 
enforcement and penalties.

Section 112.1(a)(2)--Number and Gender

    Background. We added a new Sec. 112.1(a)(2) to make clear that 
words in the singular include the plural, and words in the masculine 
include the feminine, and vice versa. This amendment is for 
clarification purposes only.

Section 112.1(b)--Facilities Covered by the Rule--Non-Transportation-
Related Facilities

    Background. We have redesignated this section to add four new 
paragraphs. This section describes generally the type of facilities 
which are subject to the SPCC rule.
    In 1991, EPA proposed changes in Sec. 112.1(b) to reflect changes 
in the geographic scope of EPA's authority under CWA section 311, as 
described in the discussion under Sec. 112.1(a)(1). EPA also proposed 
to change the phrase ``harmful quantities'' to ``quantities that may be 
harmful, as described in part 110.'' Amendments to the CWA also 
reflected the broadening of quantities that may be harmful to include 
those not only harmful to the ``public health or welfare,'' but also to 
the environment.
    Comments. Facilities. Several commenters argued that EPA 
jurisdiction, under statutory authority, does not extend to facilities, 
merely to requirements for oil spill prevention and containment 
equipment. The commenters' argument noted that the statute doesn't 
mention jurisdictional criteria relating to proximity to water or oil 
storage capacity, only EPA rules do. Therefore, the commenters argued, 
if EPA is successful in its assertion of facility regulation, then 
every pipe, valve, meter, and flange on the wellsite along with tubing 
and casing in the hole, stock tanks, drainage ditches, and roads are 
all subject to EPA jurisdiction and specifications. More importantly, 
they argued, every facility, in every industry, which at some time or 
other handles oil or hazardous substances could be subject to EPA rules 
concerning its spill prevention and containment procedures, methods, or 
equipment.
    Use of oil. Numerous commenters, especially in the electric utility 
industry, asserted that EPA has no jurisdiction to regulate the 
operational use of oil generally, or specifically in electrical 
transformers, substations, and other equipment. Some manufacturers of 
other products agreed. They argued that the legislative history of the 
Act showed no Congressional intent for such regulation. However, many 
commenters asked EPA specifically to clarify this jurisdictional issue.
    Distance to navigable waters. Two commenters proposed that we 
exempt from the rule facilities more than one mile from surface waters 
or those located outside the coastal zone.
    Response to Comments: Facilities. We disagree that our authority 
does not extend to facilities. Section 311(j)(1)(C) of the statute 
authorizes and requires the President (and EPA, through delegation in 
Executive Order 12777, 56 FR 54757, October 22, 1991) to issue 
regulations consistent with the National Oil and Hazardous Substances 
Pollution Contingency Plan, and consistent with maritime safety and 
with marine and navigation laws, which establish ``procedures, methods, 
and equipment and other requirements for equipment to prevent 
discharges of oil and hazardous substances from vessels and from 
onshore and offshore facilities, and to contain such discharges.'' This 
language authorizes the President to issue oil spill prevention rules 
which pertain to onshore facilities and offshore facilities and not 
just ``equipment.''
    In order to fulfill the statutory mandate, it is necessary to 
regulate the facilities from which discharges emanate. Moreover, 
although the term ``facility'' is not defined in the statute, both 
``onshore facility'' and ``offshore facility'' are defined terms in CWA 
section 311. They have also been defined terms in the SPCC rule since 
its inception in 1974. In the 1991 proposal, EPA proposed a definition 
of ``facility'' to implement the CWA. That definition was based on a 
Memorandum of Understanding (MOU) between the Secretary of 
Transportation and the EPA Administrator dated November 24, 1971 (36 FR 
24080). The MOU, which has been published as Appendix A to part 112 
since December 11, 1973 (38 FR 34164, 34170), defines in detail what 
constitutes a facility. Thus, there has long been a common 
understanding of the term. That understanding has been reinforced by 
frequent use of the term in context within the SPCC rule since it 
became effective in 1974. To promote clarity and to maintain all 
definitions in one place, the proposed definition has been finalized in 
this rulemaking.
    While section 311(j)(1)(C) of the Act may not explicitly mention 
jurisdictional criteria, section 311(b) of the Act does. Section 311(b) 
establishes as the policy of the United States that there shall be ``no 
discharges of oil or hazardous substances into or upon the navigable 
waters of the United States, adjoining shorelines, or into or upon the 
waters of the contiguous zone, or in connection with activities under 
the Outer Continental Shelf Lands Act or the Deepwater Port Act of 
1974, or which may affect natural resources belonging to, appertaining 
to, or under the exclusive management authority of the United States 
(including resources under the Magnuson Fishery Conservation and 
Management Act).'' Thus, the location or ``jurisdictional'' criteria 
contained in Sec. 112.1(b) are appropriate for inclusion in the rule.

[[Page 47060]]

    Use of oil. We disagree that operational equipment is not subject 
to the SPCC rule. We have amended Sec. 112.1(b) to clarify that using 
oil, for example operationally, may subject a facility to SPCC 
jurisdiction as long as the other applicability criteria apply, for 
example, oil storage capacity, or location. Such a facility might 
reasonably be expected to discharge oil as described in Sec. 112.1(b). 
Therefore, the prevention of discharges from such facility falls within 
the scope of the statute.
    However, we have distinguished the bulk storage of oil from the 
operational use of oil. We define ``bulk storage container'' in the 
final rule to mean any container used to store oil. The storage of oil 
may be prior to use, while being used, or prior to further distribution 
in commerce. For clarity, we have specifically excluded oil-filled 
electrical, operating, or manufacturing equipment from the definition.
    Facilities that use oil operationally include electrical 
substations, facilities containing electrical transformers, and certain 
hydraulic or manufacturing equipment. The requirements for bulk storage 
containers may not always apply to these facilities since the primary 
purpose of this equipment is not the storage of oil in bulk. Facilities 
with equipment containing oil for ancillary purposes are not required 
to provide the secondary containment required for bulk storage 
facilities (Sec. 112.8(c)) and onshore production facilities 
(Sec. 112.9(c)), nor implement the other provisions of Sec. 112.8(c) or 
Sec. 112.9(c). Oil-filled equipment must meet other SPCC requirements, 
for example, the general requirements of this part, including 
Sec. 112.7(c), to provide appropriate containment and/or diversionary 
structures to prevent discharged oil from reaching a navigable 
watercourse. The general requirement for secondary containment, which 
can be provided by various means including drainage systems, spill 
diversion ponds, etc., will provide for safety and also the needs of 
section 311(j)(1)(C) of the CWA.
    In addition, a facility may deviate from any inappropriate SPCC 
requirements, if the owner or operator explains his reasons for 
nonconformance and provides equivalent environmental protection by some 
other means. See Sec. 112.7(a)(2). See also Sec. 112.7(d).
    Distance to navigable waters. We do not believe that any rule which 
exempts facilities beyond any particular distance meets the intent of 
the statute. The locational standard in the rule is whether there is a 
reasonable possibility of discharge in quantities that may be harmful 
from the facility. A facility that is more than one mile from navigable 
waters might well fit within that standard. For example, piping or 
drainage from that facility might lead directly to navigable water. If 
discharged oil may reach or does reach navigable waters, adjoining 
shorelines, or protected resources, the distance which the discharged 
oil travels is irrelevant.
    Editorial changes and clarifications. In the proposed rule, this 
paragraph was designated as Secs. 112.1(b) and 112.1(b)(1). We have 
combined the paragraphs and added two new paragraphs. The new 
paragraphs describe the types of containers subject to the rule, which 
in addition to the two paragraphs we already proposed, better describe 
those containers. We also changed plural references in the proposal to 
singular throughout the section.

Section 112.1(b)(1)--Aboveground Storage Containers

    Background. We added this paragraph to clarify that aboveground 
storage containers are a subset of the containers subject to the rule. 
In 1991, we noted that containers used for standby storage, temporary 
storage, or containers that are not permanently closed, are subject to 
the rule. We also noted that bunkered tanks and partially buried tanks 
are subject to the rule. The inclusion of this paragraph and paragraph 
(b)(2), which refers to completely buried tanks, completes the universe 
of containers subject to the rule.

Section 112.1(b)(2)--Completely Buried Tanks

    Background. We added this paragraph to clarify that completely 
buried tanks are a subset of the containers subject to the rule. See 
also the discussion under Sec. 112.1(b)(1).

Section 112.1(b)(3)--Standby, Temporary, or Seasonal Storage Facilities

    Background. We proposed in 1991 to clarify that tanks used for 
standby, temporary, or seasonal storage, or that are not otherwise 
permanently closed, are subject to the SPCC rule. The Agency noted that 
such tanks are not permanently closed and can reasonably be expected to 
experience a discharge as described in Sec. 112.1(b). 56 FR 54617. The 
facilities described in Sec. 112.1(b)(3) are a subset of the facilities 
described in Sec. 112.1(b)(1) and (b)(2).
    Comments. One commenter asserted that temporarily closed tanks 
should be exempted from the rules because they are required to be 
drained and, while awaiting temporary closure, are no threat to the 
environment through oil spills. Another commenter urged that temporary 
storage facilities should be exempted from the SPCC rule, and handled 
under the Facility Response Plan (FRP) rules, found at 40 CFR 112.20-
21. A third commenter argued that frac tanks, used to store oil for the 
short periods of time while maintenance or workover operations are 
underway, should be exempted from the rule because their use is of 
short duration and does not necessarily increase the potential for 
discharge. Another commenter stated that it would be impractical to 
maintain an up-to-date SPCC Plan for temporary storage at remote parts 
of a large mining operation.
    Response to comments. If a tank is not permanently closed, it is 
still available for storage and the possibility of a discharge as 
described in Sec. 112.1(b), remains. Nor does a short time period of 
storage eliminate the possibility of such a discharge. Therefore, a 
prevention plan is necessary. A tank closed for a temporary period of 
time may contain oil mixed with sludge or residues of product which 
could be discharged. Discharges from these facilities could cause 
severe environmental damage during such temporary storage and are 
therefore subject to the rule. As to the argument that it is 
impractical to maintain an up-to-date Plan for temporary facilities at 
remote parts of mining sites, we disagree. Plans for such storage are 
analogous to or may be Plans for mobile facilities, which may be 
general Plans, but still provide environmental protection against a 
discharge as described in Sec. 112.1(b).
    Editorial changes and clarifications. In the proposed rule, this 
paragraph was designated as Sec. 112.1(b)(2). We have redesignated it 
as Sec. 112.1(b)(3).

Section 112.1(b)(4)--Bunkered, Partially Buried, and Vaulted Tanks

    Background. In 1991, we proposed to clarify that bunkered tanks, 
partially buried tanks, and tanks in subterranean vaults are considered 
aboveground tanks for purposes of the SPCC rule. The tanks or 
containers in these facilities are a subset of the facilities described 
in Sec. 112.1(b)(1). The Agency explained that compared to completely 
buried tanks, discharges from these tanks are more likely to enter 
surface waters regulated under the CWA. 56 FR 54626.
    Comments. Partially buried and bunkered tanks. A commenter 
suggested that partially buried and bunkered tanks should be considered 
underground storage tanks (USTs) and regulated under that program 
because ten percent

[[Page 47061]]

or more of the product is below grade either in the tank or in the 
pipeline. The commenter argued that tanks in compliance with the UST 
program, found at 40 CFR part 280, would not pose a significant threat 
to the environment. In fact, the commenter argued, they might be less 
likely to cause a spill than one in compliance with the SPCC rule. The 
commenter further argued that dual regulation would be unnecessarily 
burdensome without providing any additional environmental protection.
    Vaulted tanks. Several commenters asserted that since vaulted tanks 
are already regulated by fire and safety authorities, they should not 
be regulated under the SPCC program. Others argued that vaulted tanks 
meeting the technical requirements of 40 CFR part 280, or which have 
engineering controls designed to contain product released from failure 
or overfill, should likewise be exempted from the SPCC rule. These 
commenters asserted that a discharge from such tanks would not reach 
water.
    Response to comments. Partially buried and bunkered tanks. We 
disagree that partially buried tanks and bunkered tanks should be 
considered completely buried tanks, and therefore excluded from SPCC 
provisions. The rules differ in important aspects. Tanks which are 
partially underground pose a risk of a discharge as described in 
Sec. 112.1(b), which could have an adverse impact on navigable water, 
adjoining shorelines, or affected resources. Some tanks that are not 
completely buried contain engineering controls designed to prevent 
discharges. However, such controls may fail due to human or mechanical 
error and cause severe environmental damage. Such tanks may suffer 
damage caused by differential corrosion of buried and non-buried 
surfaces greater than completely buried tanks, which could cause a 
discharge as described in Sec. 112.1(b).
    Such tanks are also not subject to secondary containment 
requirements under part 280 or a State program approved under 40 CFR 
part 281. There may also be accidents during loading or unloading 
operations, or overfills resulting in a discharge to navigable waters 
and adjoining shorelines. Furthermore, a failure of such a tank (caused 
by accident or vandalism) would be more likely to cause a discharge as 
described in Sec. 112.1(b). We will, however, accept UST program forms, 
e.g., the Notification for Underground Storage Tanks, EPA Form 7530-1, 
or approved State program equivalents, insofar as such forms contains 
information relevant to the SPCC program. For example, the UST form 
(item 12) contains information regarding corrosion protection for steel 
tanks and steel piping which would be relevant for SPCC purposes. Other 
items on the form may also be relevant for SPCC purposes. We are, 
however, excluding from the rule completely buried storage tanks 
(including connected underground piping, underground ancillary 
equipment, and containment systems) that are currently subject to all 
of the technical requirements of 40 CFR part 280 or 281. See 
Sec. 112.1(d)(4).
    Vaulted tanks. Vaulted tanks are generally excluded from the scope 
of 40 CFR part 280. The definition of ``underground storage tank'' at 
40 CFR 280.12(i) excludes from its scope a ``storage tank situated in 
an underground area (such as a basement, cellar, mineworking, drift, 
shaft, or tunnel) if the storage tank is situated upon or above the 
surface of the floor.'' These tanks might reasonably experience a 
discharge as described in Sec. 112.1(b). Therefore, it is reasonable 
that they be within the scope of part 112. Merely because these tanks 
are the subject of local fire and safety regulations does not guarantee 
that there will be adequate environmental protection to prevent a 
discharge as described in Sec. 112.1(b), because that is not the 
purpose of those regulations. Such codes may provide lesser protection 
than part 112. For example, NFPA 30:2-3.4.3(b) specifically indicates 
that a dike need only provide containment for the largest tank, while 
part 112 requires freeboard for precipitation.
    Editorial changes and clarifications. In the proposed rule, this 
paragraph was designated as Sec. 112.1(b)(3). We have redesignated it 
as Sec. 112.1(b)(4). Section 112.1(b)(3) of the proposed rule uses the 
term ``aboveground storage containers,'' in place of ``aboveground 
storage tanks.'' See 56 FR 54630. We continue to use ``containers'' in 
the final rule. We deleted the word ``subterranean,'' which modified 
vaulted tanks in the proposed rule, because vaulted tanks are 
considered aboveground tanks under this rule whether they are 
subterranean or not.

Section 112.1(c)--Federal Agencies--Applicability of Rule

    Background. In 1991, we republished the already existing provisions 
of Sec. 112.1(c), which provide that agencies, departments, and 
instrumentalities of the Federal government are subject to the rule to 
the same extent as any person, except for the provisions relating to 
civil penalties. The provision relating to civil penalties was 
rescinded on March 11, 1996, because it no longer accurately reflected 
the penalties provided for under section 311(b) of the Act, as amended 
by OPA. 61 FR 9646. Therefore, we have reserved Sec. 112.6 for future 
use.
    Comments. One commenter suggested that Federal agencies are subject 
to civil penalties which are imposed under the CWA--including fines.
    Response to comments. EPA disagrees that Federal agencies are 
subject to penalties or fines under the CWA because the Federal 
government is not a ``person'' under sections 311(a)(7) or 502 of the 
CWA. Only ``persons'' (including owners or operators and persons in 
charge) are subject to such penalties. Therefore, although Federal 
agencies must comply with requirements of a CWA section 311 rule in 
accordance with CWA section 313, they are not subject to civil or 
criminal penalties or fines. See U.S. Department of Energy v. Ohio, 503 
U.S. 607, 618 (1992) (because the CWA does not define ``person'' to 
include the United States, the civil penalty provisions are not 
applicable).

Section 112.1(d)--Exemptions From Applicability

Section 112.1(d)(1)--Exemptions Based on Jurisdiction

Section 112.1(d)(1)(i)--Exemptions Based on Location

    Background. In 1991, we described the facilities, equipment, and 
operations that are exempt from the SPCC rule because they are not 
subject to the jurisdiction of EPA under section 311(j)(1)(C) of the 
Act. These facilities include those which, due to their location, could 
not be reasonably expected to have a discharge as described in 
Sec. 112.1(b).
    In making the determination of whether there is a reasonable 
possibility of a discharge as described in Sec. 112.1(b), we proposed 
that you may consider only the geographical and locational aspects of 
the facility (such as proximity to navigable waters or adjoining 
shorelines, land contour, drainage, etc.). We proposed that you could 
not consider manmade structures such as dikes, equipment, or other 
structures which may serve to restrain, hinder, or otherwise contain a 
discharge as described in Sec. 112.1(b), in making that same 
determination.
    Comments. Geographic scope of rule. One commenter agreed that the 
extension of the geographic scope of the rule will allow for more 
clarity in determining which facilities are subject to SPCC 
requirements. The commenter added that the inclusion of natural

[[Page 47062]]

resources sets the stage for the implementation of Natural Resource 
Damage Assessments, as required by the Oil Pollution Act of 1990.
    Manmade structures. Other commenters argued that EPA should modify 
its rules to provide that a facility with no reasonable possibility of 
discharge because of some combination of natural and manmade features, 
which are present for operational rather than pollution prevention 
purposes, should be excluded from the scope of the rule. Another 
commenter urged that the rule allow consideration of manmade structures 
where the structures are inherent in the design of the facility and 
serve functional and operational purposes distinct from the containment 
of oil spills.
    Groundwater. Another commenter argued that Congress intended for 
EPA to develop SPCC requirements that prevent releases to groundwater, 
in addition to requirements that prevent releases to navigable water. 
At a minimum, that commenter argued, Sec. 112.1(d)(1)(i) should contain 
language stating that clear hydrologic connections between groundwater 
underlying a facility and navigable waters require a facility to 
develop and implement an SPCC Plan. Yet another commenter, in opposing 
exemption of USTs from the SPCC program noted that groundwater 
eventually becomes surface water. The commenter added that, 
hydrologically, oil released into underground waters may migrate to 
surface water within minutes or months. The commenter argued that in 
the absence of emergency response provisions, some USTs could damage 
the nation's ground and surface water resources.
    Response to comments. Geographic scope of rule. We also believe 
that few, if any, new facilities will be subject to the rule because of 
its extension to facilities with the potential to affect certain 
natural resources. We believe that most affected facilities are either 
already subject to the rule, or not subject to our jurisdiction due to 
a Memorandum of Understanding between EPA, the U.S. Department of 
Transportation (DOT), and the U.S. Department of the Interior (DOI), 
which assigns jurisdiction over most of those facilities to DOT or DOI. 
See 40 CFR part 112, Appendix B.
    We have amended this provision to be consistent with the revised 
statutory language found in sections 311(b)(1) and (c)(1)(A) of the 
CWA. This rule focuses on preventing discharges to navigable waters, 
adjoining shorelines, the exclusive economic zone, and natural 
resources belonging to, appertaining to, or under the exclusive 
jurisdiction of the United States. Once a prohibited discharge of oil 
occurs and affects such natural resources, the NRDA provisions of OPA 
sections 1002(b)(2)(A) and 1006 apply. The National Oceanographic and 
Atmospheric Administration has promulgated a set of regulations which 
govern the process for conducting NRDAs under the OPA. 15 CFR part 990.
    Manmade structures. To allow consideration of manmade structures 
(such as dikes, equipment, or other structures) to relieve a facility 
from being subject to the rule would defeat its preventive purpose. 
Because manmade structures may fail, thus putting the environment at 
risk in the event of a discharge, there is an unacceptable risk in 
using such structures to justify relieving a facility from the burden 
of preparing a prevention plan. Secondary containment structures should 
be part of the prevention plan.
    Groundwater. EPA agrees with the commenter that groundwater 
underlying a facility that is directly connected hydrologically to 
navigable waters could trigger the requirement to produce an SPCC Plan 
based on geographic or locational aspects of the facility. See the 
discussion below for tanks regulated under 40 CFR part 280 or under a 
State program approved under 40 CFR part 281.
    EPA does not agree with the commenter that 40 CFR part 280 and a 
State program approved under 40 CFR part 281 (the rules governing most 
completely buried tanks) lack adequate emergency response provisions 
for regulated tanks and piping. 40 CFR part 280 and State programs 
approved under 40 CFR part 281 require corrective action, reporting, 
and recordkeeping requirements for any release from regulated tanks and 
piping. Also, 40 CFR parts 280 and 281 require various measures 
intended to prevent contamination that could result from releases from 
regulated tanks and piping. Although groundwater underlying a facility 
may eventually connect hydrologically to navigable waters, the 
requirements of 40 CFR part 280 and State programs approved under 40 
CFR part 281 are intended to address the prevention of releases from 
underground storage tanks that might have an impact on groundwater and 
to require rapid response and corrective action at such sites if they 
compromise groundwater quality.
    Editorial changes and clarifications. The proposed phrase in the 
first sentence which read, ``* * * could not reasonably be expected to 
discharge oil as described in Sec. 112.1(b)(1) of this part,'' becomes 
``* * * could not reasonably be expected to have a discharge as 
described in Sec. 112.1(b).'' The proposed phrase in the last sentence 
of the paragraph which read, ``* * * which may serve to restrain, 
hinder, contain, or otherwise prevent a discharge of oil from reaching 
navigable waters of the United States or adjoining shorelines. * * *'' 
becomes ``* * * which may serve to restrain, hinder, contain, or 
otherwise prevent a discharge as described in Sec. 112.1(b).''

Section 112.1(d)(1)(ii)--Exemptions Based on Function--DOT

    Background. In 1991, we republished, without substantive change, 
the current exemption for equipment or operations of vessels or 
transportation-related onshore and offshore facilities that are subject 
to the authority and control of the U.S. Department of Transportation 
(DOT). While we received no comments on the proposal, we believe that 
this provision merits a few words to clarify the understanding of the 
regulated community. The Executive Order (EO) implementing the Act 
assigns regulatory jurisdiction to three Federal agencies based on the 
function of facilities. Section 2(b)(1) of EO 12777 (56 FR 54757, 
October 22, 1991) delegates to the Administrator of EPA authority in 
section 311(j)(1)(C) relating to the establishment of procedures, 
methods, and equipment, and other requirements for equipment to prevent 
and to contain discharges of oil and hazardous substances from non-
transportation-related onshore facilities. Section 2(b)(2) of the EO 
delegates similar authority to contain discharges of oil and hazardous 
substances from vessels and transportation-related onshore facilities 
and deepwater ports to the Secretary of Transportation. Section 2(b)(3) 
of the EO delegates similar authority for offshore facilities, 
including associated pipelines, other than deepwater ports, to the 
Secretary of the Interior. A Memorandum of Understanding (MOU) among 
EPA, DOT, and the U.S. Department of the Interior (DOI), found at 
Appendix B to part 112, redelegated from DOI to EPA the responsibility 
for non-transportation-related offshore facilities located landward of 
the coastline. Similarly the MOU redelegated from DOI to DOT the 
responsibility for transportation-related offshore facilities, 
including pipelines, landward of the coastline.
    In 1993, we proposed a definition for the term ``complex,'' which 
is a facility possessing a combination of transportation-related and 
non-transportation-related components that is subject to the 
jurisdiction of more than one Federal agency under section

[[Page 47063]]

311(j) of the Clean Water Act. We published that definition on July 1, 
1994. 59 FR 34097. A commenter on the definition of ``breakout tank'' 
(see also discussion below on ``breakout tank'') asked for guidance as 
to which agency, DOT or EPA, regulates such tanks. Because of confusion 
in the regulated community over which Federal agencies have 
jurisdiction in complexes, we discuss the issue below.
    Complexes. ``Complex'' is defined at Sec. 112.2 as a ``facility 
possessing a combination of transportation-related and non-
transportation-related components that is subject to the jurisdiction 
of more than one Federal agency under section 311(j) of the Clean Water 
Act.'' The jurisdiction over a component of a complex is determined by 
the activity occurring at that component. An activity might at one time 
subject a facility to one agency's jurisdiction, and a different 
activity at the same facility using the same structure or equipment 
might subject the facility to the jurisdiction of another agency.
    Equipment, operations, and facilities are subject to DOT 
jurisdiction when they are engaged in activities subject to DOT 
jurisdiction. If those facilities are also engaged in activities 
subject to EPA jurisdiction, such activities would subject the 
equipment, operation, or facility to EPA jurisdiction. An example of an 
activity subject to EPA jurisdiction would be the loading or unloading 
of oil into a tank truck or railcar. Under an MOU between EPA and DOT 
(See Appendix A of part 112), transportation-related activities 
regulated by DOT and non-transportation-related activities regulated by 
EPA are defined. The MOU provides that highway vehicles and railroad 
cars which are used for the transport of oil in interstate or 
intrastate commerce and the equipment and appurtenances related 
thereto, and equipment used for the fueling of locomotive units, as 
well as the rights-of-way on which they operate, are considered 
transportation-related activities, subject to DOT jurisdiction.
    Another example of activities that might be considered a complex 
and therefore subject to both sets of rules is that of a breakout tank 
which is used for both transportation and non-transportation purposes. 
It is the activity to which the tank is put that determines 
jurisdiction. If you are an owner or operator of a complex, while you 
may not choose which agency will regulate your facility, you may choose 
not to engage in activities which would subject your facility to the 
jurisdiction of a particular agency if you do not wish to comply with 
that agency's rules. Otherwise, if you engage in activities subjecting 
your facility to the jurisdiction of two agencies, your facility would 
be subject to the more stringent of rules if there were to be a 
conflict or an inconsistency in those rules. For example, a facility 
with breakout tanks used solely to relieve surges in a pipeline, and 
not having another non-transportation-related activity or component, 
would not be required to have an SPCC Plan.
    Which activity would be subject to DOT jurisdiction and which 
activity which would be subject to EPA jurisdiction is defined by the 
MOU in Appendix A to part 112. The definitions in the MOU are keyed to 
the delegations of authority in EO 12777.
    Because regulatory jurisdiction is predicated upon the owner's or 
operator's activities at the facility, an owner or operator might have 
questions concerning that jurisdiction at his facility. To clarify 
regulatory jurisdiction, in February 2000, EPA and DOT signed a policy 
memorandum that described how the two agencies would work together to 
bring their respective regulations into alignment and, ultimately, to 
eliminate overlapping jurisdiction over tanks when possible.
    Recently, DOT informed EPA of a voluntary initiative to collect 
information from industry on breakout tanks, beginning in December 
2001. In anticipation of receiving the new tank information, DOT is 
considering updating the National Pipeline Mapping System (NPMS) data 
standards to reflect the guidelines for tank data submissions. 
Operators' data submissions will include the location of each tank farm 
with breakout tanks, information about each tank, and information about 
the accuracy of the data. The data will be depicted as a geospatial 
location in a digital file or a point located on a USGS 1:24,000 
topographic quad map.
    In addition to upgrading the NPMS, DOT is training its inspectors 
in tank inspection. In the President's Fiscal Year 2002 budget request, 
DOT expressed its intent to make tanks a priority in its compliance 
program, particularly where the tanks are in sensitive areas. DOT and 
EPA have agreed to provide cross-training of their respective 
personnel. As the two agencies proceed with tank oversight plans, the 
goal is to ensure that every tank is regulated and no tank is subject 
to overlapping regulations from two agencies.
    Editorial changes and clarifications. ``EPA Administrator'' becomes 
``Administrator of EPA.'' Another revision corrects an incorrect 
citation to the 1971 MOU between EPA and DOT.

Section 112.1(d)(1)(iii)--Exemptions Based on Function--DOT and DOI

    Background. We have added a new paragraph to the applicability 
section of the rule to note the jurisdictional changes resulting from 
an MOU between DOT, DOI, and EPA redelegating certain functions. The 
MOU was published on July 1, 1994 (at 59 FR 34102). The addition of 
this paragraph is not a substantive change in the rules, but merely an 
editorial revision to mark the jurisdiction of the respective agencies 
in this rule. It complements the other paragraphs in Sec. 112.1(d)(1) 
that describe facilities which are not subject to EPA jurisdiction. Due 
to the MOU, the referenced facilities, equipment, and operations of DOT 
and DOI in Sec. 112.1(d)(1)(iii), like the facilities, equipment, and 
operations described in Sec. 112.1(d)(1)(i) and (ii), are not subject 
to EPA jurisdiction under section 311(j)(1)(C) of the Act. They are not 
subject to EPA jurisdiction either because of their location, in the 
case of DOI facilities, or because of their activities, which are 
strictly transportation-related, in the case of DOT facilities.
    EO 12777 (56 FR 54757, October 22, 1991) delegates to DOI, DOT, and 
EPA various responsibilities identified in section 311(j) of the CWA. 
Sections 2(b)(3), 2(d)(3), and 2(e)(3) of EO 12777 assigned to DOI 
spill prevention and control, contingency planning, and equipment 
inspection activities associated with offshore facilities. Section 
311(a)(11) of the CWA defines the term ``offshore facility'' to include 
facilities of any kind located in, on, or under navigable waters of the 
United States. By using this definition, the traditional DOI role of 
regulating facilities on the Outer Continental Shelf was expanded by EO 
12777 to include inland lakes, rivers, streams, and any other inland 
waters.
    Under section 2(i) of EO 12777, DOI redelegated, and EPA and DOT 
accepted, the functions vested in DOI by sections 2(b)(3), 2(d)(3), and 
2(e)(3) of the EO. DOI redelegated to EPA the responsibility for non-
transportation-related offshore facilities located landward of the 
coastline. To DOT, DOI redelegated responsibility for transportation-
related facilities, including pipelines, located landward of the 
coastline. DOT retained jurisdiction for deepwater ports and the 
associated seaward pipelines. DOI retained jurisdiction over 
facilities, including pipelines, located seaward of

[[Page 47064]]

the coastline, except for deepwater ports and associated seaward 
pipelines. For purposes of the MOU, the term ``coastline'' means ``the 
line of ordinary low water along that portion of the coast which is in 
direct contact with the open sea and the line marking the seaward limit 
of inland waters.''

Section 112.1(d)(2)--Other Exemptions

Section 112.1(d)(2)(i)--Completely Buried Storage Tanks Currently 
Subject to all of the Technical Requirements of 40 CFR PART 280 or 
State Programs Approved under 40 CFR PART 281

    Background. Part 280 and approved State programs. In 1991, we 
proposed to exempt from the underground storage capacity of facilities 
in the SPCC rule the storage capacity of buried underground storage 
tanks (USTs) currently subject to all of the technical requirements of 
40 CFR part 280. We proposed this change as Sec. 112.1(d)(2)(i) in 
1991. We did not at the time include approved State programs in the 
proposal because in 1991 few if any States had such programs. In 40 CFR 
part 281 (published on September 23, 1988 at 53 FR 37212), EPA 
established regulations whereby a State could receive EPA approval for 
its State program to operate in lieu of the Federal program. In order 
to obtain EPA program approval under part 281, a State program must 
demonstrate that its requirements are no less stringent than the 
corresponding Federal regulations set forth in part 280, and that it 
provides adequate enforcement of these requirements. Thus, we have 
decided to exempt also the storage capacity of USTs subject to all of 
the technical requirements of State UST programs which EPA has 
approved. By January 2000, EPA had approved 27 State programs, plus 
programs in the District of Columbia and Puerto Rico. The rationale for 
exempting the storage capacity of these facilities from the SPCC regime 
is because 40 CFR part 280 and the approved State programs under 40 CFR 
part 281 provide comparable environmental protection for the purpose of 
preventing discharges as described in Sec. 112.1(b).
    Facilities with storage capacity not subject to part 280 or 
deferred from its provisions.
    Storage capacity not subject to part 280. Some UST facilities have 
storage capacity that is not subject to part 280, for example: any UST 
system holding hazardous wastes listed or identified under Subtitle C 
of the Solid Waste Disposal Act, or a mixture of such hazardous wastes 
and other regulated substances; wastewater treatment tank systems that 
are part of a wastewater treatment facility regulated under section 
307(b) or 402 of the Clean Water Act; equipment or machinery that 
contains regulated substances for operational purposes such as 
hydraulic lift tanks and electrical equipment tanks; and, UST systems 
whose capacity is 110 gallons or less. Also, part 280 does not provide 
for regulation of USTs storing animal fats and vegetable oils. All of 
these facilities remain potentially subject to the SPCC program.
    Tanks deferred from compliance with part 280 rules. Other 
facilities with storage capacity subject to part 280 are deferred from 
current compliance with most of the technical requirements of that 
part, including: wastewater treatment tank systems; any UST systems 
containing radioactive material that are regulated under the Atomic 
Energy Act of 1954 (42 U.S.C. 2011 et seq.); any UST system that is 
part of an emergency generator system at a nuclear power generation 
facility regulated by the Nuclear Regulatory Commission under 10 CFR 
part 50, Appendix A; airport hydrant fuel distribution systems; UST 
systems with field-constructed tanks; and, any UST system that stores 
fuel solely for use by an emergency power generator. All of these 
facilities remain potentially subject to the SPCC program.
    Tanks excluded from part 280 UST definition. Excluded from the 
definition of ``underground storage tank'' or ``UST'' in part 280 are 
a: (1) Farm or residential tank of 1,100 gallons or less capacity used 
for storing motor fuel for noncommercial purposes; (2) tank used for 
storing heating oil for consumptive use on the premises where stored; 
(3) septic tank; (4) pipeline facility (including gathering lines) 
regulated under: (a) the Natural Gas Pipeline Safety Act of 1968 (49 
U.S.C. App. 1671, et seq.), (b) the Hazardous Liquid Pipeline Safety 
Act of 1979 (49 U.S.C. App. 2001, et seq.), or (c) which is an 
intrastate pipeline facility regulated under State law comparable to 
the provisions of the Natural Gas Pipeline Safety Act of 1968 or the 
Hazardous Liquid Pipeline Safety Act of 1979; (5) surface impoundment, 
pit, pond, or lagoon; (6) storm-water or wastewater collection system; 
(7) flow-through process tank; (8) liquid trap or associated gathering 
lines directly related to oil or gas production and gathering 
operations; or, (9) storage tank situated in an underground area (such 
as a basement, cellar, mineworking, drift, shaft, or tunnel) if the 
storage tank is situated upon or above the surface of the floor. An UST 
system includes the tank itself, connected underground piping, 
underground ancillary equipment, and containment system. Therefore, any 
of these tank systems may be potentially subject to the SPCC program.
    Definitions. EPA proposed to define an UST as any tank which is 
completely covered with earth. Part 280 includes a broader definition 
of underground storage tanks, and includes partially buried and 
bunkered tanks. Partially buried tanks and bunkered tanks are excluded 
from the definition of ``completely buried tank'' in part 112, and are 
considered aboveground storage tanks (ASTs) for purposes of the rule, 
as are tanks in vaults. These tanks are not included in today's 
exemption because compared to completely buried tanks, partially buried 
and bunkered tanks are more likely to cause a discharge as described in 
Sec. 112.1(b).
    Although most USTs will be exempt from the SPCC rule (see the above 
discussion on Sec. 112.1(d)(4)), a facility might have non-exempt USTs 
for which it must prepare a facility SPCC Plan. If part of your 
facility is subject to the rule, you must mark the location and 
contents of all containers, including exempt and non-exempt USTs, on 
the facility diagram. 40 CFR 112.1(d)(4). The rationale for this 
requirement is to help response personnel to easily identify dangers 
from either fire or explosion, or physical impediments during spill 
response activities. In addition, facility diagrams may be referred to 
in the event of design modifications. 56 FR 54626.
    Capacity calculations. To calculate the 42,000-gallon threshold 
which subjects a facility operating a completely buried tank to the 
SPCC rule, you may exclude the storage capacity of any completely 
buried tank currently subject to all of the technical requirements of 
40 CFR part 280 or of an approved State program under 40 CFR part 281. 
Thus we expect you will count few completely buried tanks containing 
petroleum products in that calculation. You must count the capacity of 
completely buried tanks containing products which are not regulated 
under part 280 or an approved State program under part 281, or which 
are not currently subject to all of its technical requirements.
    Permanently closed tanks. In 1991, EPA proposed that the 
underground storage capacity of a facility does not include the 
capacity of underground tanks that are ``permanently closed'' as 
defined in Sec. 112.2. Under today's rule, you may exclude the capacity 
of tanks that are permanently closed, as defined in Sec. 112.2, in 
completely buried tank capacity calculations.

[[Page 47065]]

    Comments. Completely buried storage tanks. Favorable comments. 
Commenters overwhelmingly favored eliminating dual regulation of ASTs 
and USTs. Most agreed that the UST program provides protection 
comparable to the SPCC program. Several argued that all USTs as defined 
in part 280, which includes partially buried and bunkered tanks, should 
be exempted. Others argued that tanks deferred under the UST program 
should be exempted from the SPCC program. Another commenter suggested 
that piping connecting exempted USTs to regulated ASTs should be 
exempted from the SPCC rules. The commenter added that if such piping 
is subject to leak detection requirements for USTs under 40 CFR part 
280, then it should remain exclusively under UST rules and be exempted 
from SPCC rules.
    Opposing comments. Several commenters, however, opposed the 
proposed exemption of USTs from the SPCC program. Those commenters 
argued that the SPCC rules are not duplicative. They asserted that UST 
rules lack provisions concerning contingency planning; emergency 
response; periodic training of personnel to deal with emergencies; 
maintenance of records regarding inspections and tests; maintenance of 
records regarding discharges to navigable waters or adjoining 
shorelines; diking of fuel transfer areas; fuel transfer area 
operational procedures; illumination of fuel transfer areas; stormwater 
drainage system design; posting of vehicle weight restrictions in areas 
where there is underground piping and/or design of underground piping 
to withstand vehicular loadings; a requirement for an application of 
``good engineering practice,'' in other words, no requirements that the 
design and construction of a UST system be overseen by a Professional 
Engineer; a requirement that management sign the Plan; and, ``other 
topics enumerated in 40 CFR 112.7.'' One commenter noted that since 
groundwater becomes surface water eventually, whether within minutes or 
months, the absence of emergency provisions in the UST program might 
cause environmental problems. Another commenter argued that the new 
regulatory scheme would be confusing because a facility might have some 
containers subject to SPCC and some that are not, as well as containers 
that may be subject to State regulation.
    Response to comments. Completely buried storage tanks. As we noted 
above, in the discussion of Sec. 112.1(d)(1)(i), the UST program 
provides comparable environmental protection to the SPCC program. While 
not all aspects of the programs are identical, the UST program ensures 
protection against discharges as described in Sec. 112.1(b), and 
protection of the environment. Therefore, dual regulation is 
unnecessary. In response to commenters asserting that UST rules lack 
provisions concerning contingency planning; emergency response; certain 
recordkeeping requirements; and other alleged deficiencies, we 
disagree. The UST rules have numerous safeguards addressing the 
commenter's issues.
    Partially buried tanks and bunkered tanks. We disagree that 
partially buried tanks and bunkered tanks should be considered 
completely buried tanks, and therefore excluded from SPCC provisions. 
Such tanks may suffer damage caused by differential corrosion of buried 
and non-buried surfaces greater than completely buried tanks, which 
could cause a discharge as described in Sec. 112.1(b). Such tanks are 
also not subject to secondary containment requirements under part 280 
or a State program approved under 40 CFR part 281. There may also be 
accidents during loading or unloading operations, or overfills 
resulting in a discharge to navigable waters and adjoining shorelines. 
Furthermore, a failure of such a tank (caused by accident or vandalism) 
would be more likely to cause a discharge as described in 
Sec. 112.1(b).
    Contingency planning. While it is true that UST rules do not 
require contingency planning, spills and overfills of USTs resulting in 
a discharge to the environment are much less likely as a result of 
those rules. An owner or operator of an underground storage tank 
subject to 40 CFR part 280 or a State program approved under 40 CFR 
part 281 was required to install spill and overfill prevention 
equipment no later than December 22, 1998. 40 CFR 280.20 and 280.21. 
The use of this equipment will greatly reduce the likelihood of both 
small and large releases or discharges of petroleum to the environment 
through surface spills or overfilling underground storage tanks. In 
addition, the UST rules place a general responsibility on the owner or 
operator to ensure that discharges due to spilling and overfilling do 
not occur. See 40 CFR 280.30.
    Emergency response and release reporting. The UST rules also have 
several requirements related to emergency response and release or 
discharge reporting. The UST rules generally require that releases of 
regulated substances be reported to the implementing agency within 24 
hours. As part of the initial response requirements (found at 40 CFR 
280.61), an owner or operator must take immediate action to prevent 
further release of the regulated substance and must identify and 
mitigate fire, explosion, and vapor hazards.
    Reporting and recordkeeping. In addition to the reporting 
requirements mentioned above, there are numerous reporting and 
recordkeeping requirements in the rules governing underground storage 
tanks. Among these are: corrective action plans; documentation of 
corrosion protection equipment; documentation of UST system repairs; 
and, information concerning recent compliance with release detection 
requirements. Thus, the UST rules have significant reporting and 
recordkeeping requirements, including specific requirements related to 
spills and overfills.
    Transportation rules. In addition to the EPA UST rules, the U.S. 
Department of Transportation has hazardous material regulations related 
to driver training, emergency preparation, and incident reporting and 
emergency response. Training regulations, for example, can be found at 
49 CFR part 172, and loading and unloading regulations can be found at 
49 CFR 177.834 and 49 CFR 177.837. These regulations apply, for 
example, to truck drivers delivering gasoline or diesel fuel to gas 
stations with underground storage tanks.
    Section 112.1(f). Finally, as a safeguard, today's rule (see 
Sec. 112.1(f) in today's preamble) provides the Regional Administrator 
with the authority to require any facility subject to EPA jurisdiction 
under section 311 of the CWA, regardless of threshold or other 
regulatory exemption, to prepare and implement an SPCC Plan when 
necessary to further the purposes of the Act.
    Regulatory jurisdiction. To eliminate any possible confusion over 
regulatory jurisdiction, we explain in this preamble (see the above 
background discussion) which containers in a facility are subject to 40 
CFR part 280 or a State program approved under 40 CFR part 281 and 
which are subject to part 112.
    Piping, ancillary equipment, and containment systems. EPA has 
modified the scope of the proposed exemption for completely buried 
tanks (which are excluded from the scope of the SPCC rule if they are 
subject to all of the technical requirements of 40 CFR part 280 or a 
State program approved under 40 CFR part 281) by clarifying that the 
exemption includes the connected underground piping, underground 
ancillary equipment, and containment

[[Page 47066]]

systems, in addition to the tank itself. This modification is 
consistent with the definition of underground storage tank system found 
at 40 CFR 280.12. In addition, this clarification is responsive to the 
comment which asked that the piping be included in the exemption.
    Deferred tanks. We disagree that we should not regulate tanks which 
are deferred from compliance with any of the technical requirements of 
40 CFR part 280 or a State program approved under 40 CFR part 281. 
These are containers from which a discharge as described in 
Sec. 112.1(b) may occur, and thus are properly subject to the SPCC 
rule. Furthermore, if they were not regulated by SPCC rules, they may, 
in some instances, not be regulated at all.
    Effect on Facility Response Plan facilities. The exemption for 
completely buried tanks subject to all the technical requirements of 40 
CFR part 280 or a State program approved under 40 CFR part 281 applies 
to the calculation of storage capacity both for SPCC purposes and for 
Facility Response Plan (FRP) purposes because the exemption applies to 
all of part 112. Therefore, a few FRP facilities with large capacity 
completely buried tanks subject to 40 CFR part 280 or a State program 
approved under 40 CFR part 281 might no longer be required to have 
FRPs. Calculations for planning levels for worst case discharges will 
also be affected. However, the Regional Administrator retains authority 
to require the owner or operator of any non-transportation-related 
onshore facility to prepare and submit a FRP after considering the 
factors listed in Sec. 112.20(f)(2). See Sec. 112.20(b)(1).
    Editorial changes and clarifications. ``Underground storage tanks'' 
becomes ``completely buried storage tanks.'' The phrase ``does not 
include'' becomes ``excludes.'' We have amended the rule to clarify 
that facilities must be subject to ``all of'' the technical 
requirements of 40 CFR part 280 or of a State program approved under 40 
CFR part 281 to qualify for the SPCC exemption. If a facility is 
subject to some, but not all of the UST requirements, it may be subject 
to the SPCC rule. Facilities in this category include those which are 
excluded from UST requirements, or deferred from compliance with some 
or all of those requirements.

Section 112.1(d)(2)(ii)--AST Threshold, Minimum Container Size, 
Permanently Closed Tanks

    Background. Regulatory thresholds. In the 1997 preamble, we asked 
for comment as to whether any change in the level of storage capacity 
which subjects a facility to this rule is justified. 62 FR 63813. We 
noted that we were considering eliminating the provision in the current 
rule that requires a facility having an aboveground container in excess 
of 660 gallons to prepare an SPCC Plan, as long as the total 
aboveground capacity of the facility remained at 1,320 gallons or less. 
The effect of such a change would be to raise the threshold for 
regulation to an aboveground storage capacity greater than 1,320 
gallons.
    In 1991, EPA also proposed that the aboveground storage capacity of 
a facility does not include the capacity of aboveground storage 
containers that are ``permanently closed'' as defined in Sec. 112.2.
    Comments. Minimum size container. Numerous commenters suggested a 
de minimis size for containers to be used for AST capacity 
calculations. Most of the suggestions came in the context of the 
discussion of the proposed definition of ``bulk storage tank.'' 
Suggestions for a minimum size ranged from over 55 gallons to 25,000 
gallons. The bulk of the commenters favored either a greater than 55-
gallon number, or a greater than 660-gallon figure.
    Regulatory thresholds. Higher threshold. Commenters offered 
numerous threshold levels in both 1991 and 1997. Suggestions for the 
regulatory threshold in 1991 ranged from greater than 1,320 gallons to 
120,000 gallons. Many commenters, particularly utilities, favored 
thresholds in the 10,000-42,000-gallon range. In 1997, when EPA 
suggested it might consider a greater than 1,320-gallon threshold, many 
commenters favored that suggestion. Others urged thresholds ranging up 
to 15,000 gallons.
    Lower threshold. A few commenters suggested lowering the threshold. 
Commenters suggested threshold levels of 110 and 250 gallons. The 
general rationale for these suggestions was that oil spills causing 
even a sheen can be devastating. Therefore, these commenters reasoned 
that sheens from home heating oil tanks of 110 gallons, i.e., two 55-
gallon drums, are every bit as important as sheens from crude oil 
tanks. An advocate for a lower threshold noted that manufacturers now 
sell, market, and produce fuel containers of 650 gallons designed to 
avoid compliance with the rule, whether the site is adjacent to 
navigable waterways or not. The commenter added that most manufacturers 
market or sell a ``listed'' tank of 250 gallons, and that under current 
rules, five of these tanks would not subject a facility to the SPCC 
rule, yet the risk would be nearly identical to one larger tank of 
1,250 gallons depending upon the design of the tank.
    Response to comments. Minimum container size. In response to 
comments, we are introducing a minimum container size. The 55 gallon 
container is the most widely used commercial bulk container, and these 
containers are easily counted. Containers below 55 gallons in capacity 
are typically end-use consumer containers. Fifty-five gallon containers 
are also the lowest size bulk container that can be handled by a human. 
Containers above that size typically require equipment for movement and 
handling. We considered a minimum container size of one barrel. 
However, a barrel or 42 gallons is a common volumetric measurement size 
for oil, but is not a common container size. Therefore, it would not be 
appropriate to institute a 42 gallon minimum container size.
    You need only count containers of 55 gallons or greater in the 
calculation of the regulatory threshold. You need not count containers, 
like pints, quarts, and small pails, which have a storage capacity of 
less than 55 gallons. Some SPCC facilities might therefore drop out of 
the regulated universe of facilities. You should note, however, that 
EPA retains authority to require any facility subject to its 
jurisdiction under section 311(j) of the CWA to prepare and implement 
an SPCC Plan, or applicable part, to carry out the purposes of the Act.
    While some commenters had suggested a higher threshold level, we 
believe that inclusion of containers of 55 gallons or greater within 
the calculation for the regulatory threshold is necessary to ensure 
environmental protection. If we finalized a higher minimum size, the 
result in some cases would be large amounts of aggregate capacity that 
would not be counted for SPCC purposes, and would therefore be 
unregulated, posing a threat to the environment. We believe that it is 
not necessary to apply SPCC or FRP rules requiring measures like 
secondary containment, inspections, or integrity testing, to containers 
smaller than 55 gallons storing oil because a discharge from these 
containers generally poses a smaller risk to the environment. 
Furthermore, compliance with the rules for these containers could be 
extremely burdensome for an owner or operator and could upset 
manufacturing operations, while providing little or no significant 
increase in protection of human health or the environment. Many of 
these smaller containers are constantly being emptied, replaced, and 
relocated so that serious corrosion will likely soon be detected and 
undetected leaks become highly unlikely. While we realize that small 
discharges may harm

[[Page 47067]]

the environment, depending on where and when the discharge occurs, we 
believe that this measure will allow facilities to concentrate on the 
prevention and containment of discharges of oil from those sources most 
likely to present a more significant risk to human health and the 
environment.
    Effect on Facility Response Plan facilities. The exemption for 
containers of less than 55 gallons applies to the calculations of 
storage capacity both for SPCC purposes and for FRP purposes because 
the exemption applies to all of part 112. Therefore, a few FRP 
facilities might no longer be required to have FRPs. The calculations 
for planning levels for worst case discharges would also be affected.
    Regulatory thresholds. We have decided to raise the current 
regulatory threshold, as discussed in the 1997 preamble, to an 
aggregate threshold of over 1,320 gallons. We believe that raising the 
regulatory threshold is justified because our Survey of Oil Storage 
Facilities (published in July 1996, and available on our Web site at 
www.epa.gov/oilspill) points to the conclusion that several facility 
characteristics can affect the chances of a discharge. First, the 
Survey showed that as the total storage capacity increases, so does the 
propensity to discharge, the severity of the discharge, and the costs 
of cleanup. Likewise, the Survey also pointed out that as the number of 
tanks increases, so does the propensity to discharge, the severity of 
the discharge, and the costs of cleanup. Finally, the Survey showed 
that as annual throughput increases, so does the propensity to 
discharge, the severity of the discharge, and, to a lesser extent, the 
costs of the cleanup.
    The threshold change will have several benefits. The threshold 
increase will result in a substantial reduction in information 
collection associated with the rule overall. Some smaller facilities 
will no longer have to bear the costs of an SPCC Plan. EPA will be 
better able to focus its regulatory oversight on facilities that pose a 
greater likelihood of a discharge as described in Sec. 112.1(b), and a 
greater potential for injury to the environment if a discharge as 
described in Sec. 112.1(b) results.
    We raise the regulatory threshold realizing that discharges as 
described in Sec. 112.1(b) from small facilities may be harmful, 
depending on the surrounding environment. Among the factors remaining 
to mitigate any potential disasters are that small facilities no longer 
required to have SPCC Plans are still liable for cleanup costs and 
damages from discharges as described in Sec. 112.1(b). We encourage 
those facilities exempted from today's rule to maintain SPCC Plans. 
Likewise, we encourage facilities becoming operable in the future with 
storage or use capacity below the regulatory threshold to develop 
Plans. We believe that SPCC Plans have utility and benefit for both the 
facility and the environment. But, we will no longer by regulation 
require Plans from exempted facilities.
    While we believe that the Federal oil program is best focused on 
larger risks, State, local, or tribal governments may still decide that 
smaller facilities warrant regulation under their own authorities. In 
accord with this philosophy, we note that this Federal exemption may 
not relieve all exempted facilities from Plan requirements because some 
States, local, or tribal governments may still require such facilities 
to have Plans. While we are aware that some States, local, or tribal 
governments have laws or policies allowing them to set requirements no 
more stringent than Federal requirements, we encourage States, local, 
or tribal governments to maintain or lower regulatory thresholds to 
include facilities no longer covered by Federal rules where their own 
laws or policies allow. We believe that CWA section 311(o) authorizes 
States to establish their own oil spill prevention programs which can 
be more stringent than EPA's program.
    Regulatory safeguard. When a particular facility that is below 
today's threshold becomes a hazard to the environment because of its 
practices, or when needed for other reasons to carry out the Clean 
Water Act, the Regional Administrator may, under a new rule provision, 
require that facility to prepare and implement an SPCC Plan. See 
Sec. 112.1(f). This provision acts as a safeguard to an environmental 
threat from any exempted facility.
    Editorial changes and clarifications. The reference to 
``underground storage tanks'' was deleted because it is unnecessary. A 
reference to the exemption of certain ``completely buried'' storage 
tanks from the rules is contained in Sec. 112.1(d)(4).

Section 112.1(d)(3)--Minerals Management Service Facilities

    Background. In 1991, EPA proposed to exempt from the SPCC rule 
facilities subject to Minerals Management Service (MMS) Operating 
Orders, notices, and regulations. The rationale for the 1991 proposal 
was to avoid redundancy in regulation, based on EPA's analysis that MMS 
Operating Orders require adequate spill prevention, control, and 
countermeasures that are directed more specifically to the facilities 
subject to MMS requirements. Until October 22, 1991, the date of the 
1991 proposed rule, responsibility for the establishment of procedures, 
methods, and equipment and other requirements for equipment to prevent 
and to contain discharges of oil from offshore facilities, including 
associated pipelines, other than deepwater ports subject to the 
Deepwater Ports Act, was delegated to EPA. Under EO 12777 (56 FR 54747, 
October 22, 1991), responsibility for the establishment of procedures, 
methods, and equipment and other requirements for equipment to prevent 
and to contain discharges of oil from offshore facilities, including 
associated pipelines, other than deepwater ports subject to the 
Deepwater Ports Act, was redelegated to the U.S. Department of the 
Interior (DOI). These facilities are generally offshore oil production 
or exploration facilities.
    In 1994, in another Memorandum of Understanding (MOU) found in 
Appendix B of part 112, EPA, DOI, and DOT redelegated the 
responsibility to regulate non-transportation-related offshore 
facilities located in and along the Great Lakes, rivers, coastal 
wetlands, and the Gulf Coast barrier islands from DOI to EPA.
    Because of the redelegation of responsibility, some DOI facilities 
again became subject to the jurisdiction of EPA under section 
311(j)(1)(C) of the Act. We added a reference to the MOU in the rule.
    Comments. Most commenters favored the proposed exemption because 
they believed that MMS orders, notices, and regulations require oil 
spill prevention and contingency planning equivalent to the 
environmental protection envisioned by EPA's rules. Two commenters, 
both States, opposed the proposal. One was concerned with MMS' 
``historic treatment of identified violations.'' The other suggested 
that the more stringent of EPA or MMS regulations apply.
    Response to comments. We have retained our original proposal, 
except for the editorial revision, because we believe that MMS will 
provide equivalent environmental protection for the facilities under 
its jurisdiction. MMS regulations require adequate spill prevention, 
control, and countermeasures that are directed more specifically to the 
facilities subject to MMS requirements.
    Editorial changes and clarifications. The term ``Operating Orders'' 
becomes ``regulations.''

[[Page 47068]]

Section 112.1(d)(4)--Completely Buried Storage Tanks

    Background. This paragraph is a companion paragraph to 
Sec. 112.1(d)(2)(i) for purposes of SPCC exemption. As in 
Sec. 112.1(d)(2)(i), we have also exempted connected underground 
piping, underground ancillary equipment, and containment systems 
subject to all of the technical requirements of part 280 or a State 
program approved under 40 CFR part 281. We also added a clause noting 
that these exempted tanks must be marked on the facility diagram as 
provided in Sec. 112.7(a)(3), if the facility is otherwise subject to 
this part. See the discussion above concerning Sec. 112.1(d)(2)(i).
    Editorial changes and clarifications. ``Underground storage tanks'' 
becomes ``completely buried storage tanks.'' We also reference 40 CFR 
part 281.

Section 112.1(d)(5)--Minimum Size Exemption

    Background. This is a new section we added in response to comments 
pertaining to the regulatory threshold/minimum container size issue 
discussed above. This section clarifies that any aboveground or 
completely buried container with capacity of less than 55 gallons is 
not subject to the rule. It is a companion rule to Sec. 112.1(d)(2)(ii) 
for purposes of SPCC exemption. See the discussion above concerning 
Sec. 112.1(d)(2)(ii).

Section 112.1(d)(6)--Wastewater Treatment Facility Exemption

    Background. In 1991, EPA proposed various changes to Sec. 112.1(d) 
concerning exemptions to part 112, and received comments on its 
proposals. Among those comments was one suggesting an exemption for 
certain treatment systems.
    Comments. One commenter suggested that the ``Sec. 112.1 exceptions 
should be expanded to include facility storage and treatment tanks 
associated with `non-contact cooling water systems' and/or `storm water 
retention and treatment systems.' Although these tanks are designed to 
remove spilled oil from manufacturing operations and parking lot 
runoff, the concentration of oil in the water at any given time would 
be insignificant. These tanks are typically very large, i.e., in excess 
of 100,000 gallons, and are typically not contained by diked walls or 
impervious surfaces. GM believes the cost to contain these structures 
could be better spent on other SPCC regulatory requirements.''
    Response to comments. We agree with the commenter that certain 
wastewater treatment facilities or parts thereof should be exempted 
from the rule, if used exclusively for wastewater treatment and not 
used to meet any other requirement of part 112. We have therefore 
amended the rule to reflect that agreement. No longer subject to the 
rule would be wastewater treatment facilities or parts thereof such as 
treatment systems at POTWs and industrial facilities treating oily 
wastewater.
    Many of these wastewater treatment facilities or parts thereof are 
subject to NPDES or state-equivalent permitting requirements that 
involve operating and maintaining the facility to prevent discharges. 
40 CFR 122.41(e). The NPDES or state-equivalent process ensures review 
and approval of the facility's: plans and specifications; operation/
maintenance manuals and procedures; and, Stormwater Pollution 
Prevention Plans, which may include Best Management Practice Plans 
(BMP).
    Many affected facilities are subject to a BMP prepared under an 
NPDES permit. Some of those plans provide protections equivalent to 
SPCC Plans. BMPs are additional conditions which may supplement 
effluent limitations in NPDES permits. Under section 402(a)(1) of the 
CWA, BMPs may be imposed when the Administrator determines that such 
conditions are necessary to carry out the provisions of the Act. See 40 
CFR 122.44(k). CWA section 304(e) authorizes EPA to promulgate BMPs as 
effluent limitations guidelines. NPDES rules provide for BMPs when: 
authorized under section 304(e) of the CWA for the control of toxic 
pollutants and hazardous substances; numeric limitations are 
infeasible; or, the practices are reasonably necessary to achieve 
effluent limitations and standards to carry out the purposes of the 
CWA. In addition, each NPDES or state equivalent permit for a 
wastewater treatment system must contain operation and maintenance 
requirements to reduce the risk of discharges. 40 CFR 122.41(e).
    Additionally, some wastewater is pretreated prior to discharge to a 
permitted wastewater treatment facility. The CWA authorizes EPA to 
establish pretreatment standards for pollutants that pass through or 
interfere with the operation of POTWs. The General Pretreatment 
Regulations (GPR), which set for the framework for the implementation 
of categorical pretreatment standards, are found at 40 CFR part 403. 
The GPR prohibit a user from introducing a pollutant into a POTW which 
causes pass through or interference. 40 CFR 403.5(a)(1). More 
specifically, the GPR also prohibit the introduction into of POTW of 
``petroleum, oil, nonbiodegradable cutting oil, or products of mineral 
oil origin in amounts that will cause interference or pass through. 40 
CFR 403.5(b)(6). EPA believes that the GPR and the more specific 
categorical pretreatment standards, some of which allow indirect 
dischargers to adopt a BMP as an alternative way to meet pretreatment 
standards, will work to prevent the discharge of oil from wastewater 
treatment systems into navigable waters or adjoining shorelines by way 
of a POTW.
    However, if a wastewater facility or part thereof is used for the 
purpose of storing oil, then there is no exemption, and its capacity 
must be counted as part of the storage capacity of the facility. Any 
oil storage capacity associated with or incidental to these wastewater 
treatment facilities or parts thereof continues to be subject to part 
112. At permitted wastewater treatment facilities, storage capacity 
includes bulk storage containers, hydraulic equipment associated with 
the treatment process, containers used to store oil which feed an 
emergency generator associated with wastewater treatment, and slop 
tanks or other containers used to store oil resulting from treatment. 
Some flow through treatment such as oil/water separators have a storage 
capacity within the treatment unit itself. This storage capacity is 
subject to the rule. An example of a wastewater treatment unit that 
functions as storage is a treatment unit that accumulates oil and 
performs no further treatment, such as a bulk storage container used to 
separate oil and water mixtures, in which oil is stored in the 
container after removal of the water in the separation/treatment 
process.
    We do not consider wastewater treatment facilities or parts thereof 
at an oil production, oil recovery, or oil recycling facility to be 
wastewater treatment for purposes of this paragraph. These facilities 
generally lack NPDES or state-equivalent permits and thus lack the 
protections that such permits provide. Production facilities are 
normally unmanned and therefore lack constant human oversight and 
inspection. Produced water generated by the production process normally 
contains saline water as a contaminant in the oil, which might 
aggravate environmental conditions in addition to the toxicity of the 
oil in the case of a discharge.
    Additionally, the goal of an oil production, oil recovery, or oil 
recycling facility is to maximize the production or recovery of oil, 
while eliminating impurities in the oil, including water, whereas the 
goal of a wastewater

[[Page 47069]]

treatment facility is to purify water. Neither an oil production 
facility, nor an oil recovery or oil recycling facility treats water, 
instead they treat oil. For purposes of this exemption, produced water 
is not considered wastewater and treatment of produced water is not 
considered wastewater treatment. Therefore, a facility which stores, 
treats, or otherwise uses produced water remains subject to the rule. 
At oil drilling, oil production, oil recycling, or oil recovery 
facilities, treatment units subject to the rule include open oil pits 
or ponds associated with oil production operations, oil/water 
separators (gun barrels), and heater/treater units. Open oil pits or 
ponds function as another form of bulk storage container and are not 
used for wastewater treatment. Open oil pits or ponds also pose 
numerous environmental risks to birds and other wildlife.
    Examples of wastewater treatment facilities or parts thereof used 
to meet a part 112 requirement include an oil/water separator used to 
meet any SPCC requirement. Oil/water separators used to meet SPCC 
requirements include oil/water separators used as general facility 
secondary containment (i.e., Sec. 112.7(c), secondary containment 
requirements for loading and unloading (i.e., Sec. 112.7(h)), and for 
facility drainage (i.e., Sec. 112.8(b) or Sec. 112.9(b)).
    Whether a wastewater treatment facility or part thereof is used 
exclusively for wastewater treatment (i.e., not storage or other use of 
oil) or used to satisfy a requirement of part 112 will often be a 
facility specific determination based on the activity associated with 
the facility or part thereof. Only the portion of the facility (except 
at an oil production, oil recovery, or oil recycling facility) used 
exclusively for wastewater treatment and not used to meet any part 112 
requirement is exempt from part 112. Storage or use of oil at such a 
facility will continue to be subject to part 112.
    Although we exempt wastewater treatment facilities or parts thereof 
from the rule under certain circumstances, a mixture of wastewater and 
oil still is ``oil'' under the statutory and regulatory definition of 
the term (33 U.S.C. 1321(a)(1) and 40 CFR 110.2 and 112.2). Thus, while 
we are excluding from the scope of the rule certain wastewater 
treatment facilities or parts thereof, a discharge of wastewater 
containing oil to navigable waters or adjoining shorelines in a 
``harmful quantity'' (40 CFR part 110) is prohibited. Thus, to avoid 
such discharges, we would expect owners or operators to comply with the 
applicable permitting requirements, including best management practices 
and operation and maintenance provisions.

Proposed Sec. 112.1(e)--Facility Notification

    Background. In 1991, EPA proposed to require that any facility 
subject to its jurisdiction under the Clean Water Act which also meets 
the regulatory storage capacity threshold notify the Agency on a one-
time basis of its existence. CWA section 311(m) provides EPA with the 
authority to require the owner or operator of a facility subject to 
section 311 to make reports and provide information to carry out the 
objectives of section 311. Any owner or operator who failed to notify 
or knowingly submitted false information in a notification would be 
subject to a civil penalty. This type of notice is separate from the 
notice required at 40 CFR 110.3 of discharges which may be harmful to 
the public health or welfare or the environment. We did not propose any 
changes to the notice requirements in Sec. 110.3.
    We proposed that facility notification include, among other items, 
information concerning the number, size, storage capacity, and 
locations of ASTs. The proposal would have exempted information 
regarding the number and size of completely buried tanks, as defined in 
Sec. 112.2, from the notification requirement. The rationale for 
notification was that submission of this information would be needed to 
help us identify our universe of facilities and to help us administer 
the Oil Pollution Prevention Program by creating a data base of 
facility-specific information. We also asked for comments regarding the 
form on which notification would be submitted, and on various possible 
items of information that could be included besides the ones proposed. 
Lastly, we asked for comments on alternate forms of facility 
notification. 56 FR 54614-15.
    Comments. Favorable comments. A number of commenters favored the 
proposal, including some industry commenters. These commenters stated 
that there was generally no current procedure whereby EPA can identify 
the universe of sites subject to the SPCC rule, and that an inventory 
of these facilities is necessary.
    Opposing comments. Most industry commenters opposed the proposal 
either in part or in its entirety.
    Sources of information. Commenters who opposed the proposal in its 
entirety asserted that it was unnecessary, largely because they 
believed the information sought might be better obtained from other 
sources, such as State sources or SARA Title III reports. Some States 
wanted copies of the notifications EPA would receive, and at least one 
suggested requiring updates. One commenter suggested that we gather the 
information through representative sampling at on-site surveys. Another 
commenter suggested that we use spill reports already submitted because 
it makes more sense to regulate those facilities whose practices have 
led to a spill.
    Applicability. Other commenters criticized the fact that the 
proposal would have been applicable to facilities which were not 
subject to the SPCC rule. Their solution was to limit applicability to 
facilities currently regulated under part 112.
    Terrorism. One commenter suggested that the aggregation of such 
strategic information in an easily accessed data base like a facility 
notification data base could provide an intelligence windfall to 
terrorists and other enemies of our nation.
    Small facilities. Commenters for small facilities argued that 
facility notification would cause a deluge of notifications to be sent 
to EPA with little or no environmental benefit. Some of these 
commenters suggested exempting small facilities at various levels of 
storage capacity, for example, 42,000 gallons or 100,000 gallons.
    Notification time line. In particular, commenters questioned 
various aspects of the proposal. Many questioned the necessity of 
providing the information within the proposed two months time frame. 
Some commenters suggested other time periods ranging from ``more than 
two months'' to 18 months. However, the bulk of the commenters favored 
a six month period for facility notification if notification were to be 
required. Others favored a ``phase-in'' of the requirements.
    Who must notify. Some commenters asked who must notify, the owner 
or operator. They noted that these might be different persons. One 
commenter suggested that the operator of the facility, the owner of any 
improvements at the facility, and the owner of the land at the facility 
should be required to submit facility notification. The commenter 
argued that the United States government is the landowner most 
prejudiced by the absence of a requirement of landowner involvement in 
the preparation of an SPCC plan because an owner or operator can 
prepare a minimal SPCC Plan and not even inform the landowner of it.
    Location issues. Others questioned the proposed requirement for the 
name, address, and zip code of the facility, arguing that provision of 
such information was not always possible,

[[Page 47070]]

especially in remote rural areas. Some noted that drilling rigs move 
from location to location as often as every few months. Commenters 
suggested alternatives such as use of longitude and latitude, or the 
Universal Transverse Mercator system, or a mailing address.
    Storage capacity. A number of commenters had concerns about the 
requirement for the total number and size of ASTs, and the total AST 
capacity of the facility. Commenters noted that there was no space on 
the form for containers less than 250 gallons. Other commenters asked 
if additions to storage capacity would trigger a new notification. Some 
commenters believed that storage capacity could be measured by SARA 
Title III information.
    Distance to navigable waters. The proposed requirement to detail 
the distance to the nearest navigable water elicited many comments. 
Some commenters noted that there was no definition of navigable waters 
on the form, making it difficult for some responders to answer the 
question. Others asserted that making the determination on distance to 
navigable waters was a difficult one due to litigation concerning the 
definition of the term. Yet other commenters thought that we should 
specify a minimum distance to navigable waters, on the theory that only 
facilities within a certain distance would have a reasonable 
possibility of discharge to such waters.
    Classification of facilities. One commenter noted that exploration 
and production facilities rarely have Dun & Bradstreet numbers, and 
that the information received from Dun & Bradstreet might be irrelevant 
for our purposes. Regarding the reporting of Standard Industrial 
Classification codes (SIC) (now replaced by North American Industry 
Classification System (NAICS) codes), commenters asserted that EPA used 
inaccurate codes, that no codes were listed for edible oil facilities, 
and that the codes listed were misleading in that they did not cover 
all possible industries regulated.
    Use of oil. Permanently closed containers. Facilities using 
primarily oil-filled equipment, not bulk storage containers, asked 
whether they too were covered by the notification proposal. Other 
commenters asked for clarification as to whether permanently closed 
tanks were covered by the proposal.
    Possible additional items. There were numerous comments on various 
additional items for which EPA had requested comment, but which were 
not included in the proposal. Possible additional items included: 
latitude and longitude of the facility; location of environmentally 
sensitive areas and potable water supplies; presence of secondary 
containment; spill history; leak detection equipment and alarms; age of 
the tanks; potential for adverse weather; and, for field verification 
purposes, a requirement to have storage facilities placarded or 
similarly identified. Most commenters opposed the inclusion of 
additional items. Several supported these additions as well as the 
addition of other information, particularly information concerning tank 
materials, methods of construction (for example, field-or shop-erected) 
and substance stored.
    Response to comments. Withdrawal of proposal. We have decided to 
withdraw the proposed facility notification requirement because we are 
still considering issues associated with establishing a paper versus 
electronic notification system, including issues related to providing 
electronic signatures on the notification. Should the Agency in the 
future decide to move forward with a facility notification requirement, 
we will repropose such requirement.

Section 112.1(e)--Proposed as Sec. 112.1(f)--Compliance With Other Laws

    Background. While today's rule is substantially similar to the 
current one, EPA suggested in the 1991 preamble that facility owners 
consider industry standards in preparing SPCC Plans. 56 FR 54617.
    Comments. State rules. Several States wrote to ask EPA to be as 
consistent with current State rules as possible. One industry commenter 
complained that EPA rules were more stringent than some State rules. 
Other industry commenters opposed either State or Federal regulation, 
or both.
    Industry standards. Several commenters wrote to urge that EPA 
incorporate industry standards into the rule, on the theory that if EPA 
wants to require these standards, they must be incorporated into the 
rule. Others wrote to urge the inclusion of specific standards, such as 
fire codes or steel tank codes.
    Response to comments. State rules. Section 311(o)(2) of the CWA 
specifically provides that nothing in section 311 ``shall be construed 
as preempting any State or political subdivision thereof from imposing 
any requirements or liability with respect to the discharge of oil * * 
*.'' We are aware that Federal rules often set the standard for State 
rules, and at least set a floor for State rules. Under CWA section 
311(o)(2), States are free to impose more stringent standards relating 
to prevention of oil discharges, or none at all. EPA encourages States 
to set up their own oil pollution prevention programs because we 
believe that oil pollution prevention efforts should be a joint 
Federal-State effort.
    Industry standards. Under this rule, a facility is required to at 
least consider the use of all relevant measures, including the use of 
industry standards, as a way to implement those measures. The 
requirement comes in the language of revised Sec. 112.3(d)(1)(iii) 
requiring the PE to attest that ``the Plan has been prepared in 
accordance with good engineering practice, including consideration of 
applicable industry standards, and with the requirements of this 
part.'' A facility should use industry standards whenever possible in 
preparing and implementing its SPCC Plan, and should discuss their use 
in Plans. While facility owners or operators should look to specific 
industry standards as a guide for preparing SPCC Plans, we do not 
believe that incorporating specific standards into this rule is 
appropriate. Such incorporation freezes standards into rules, which may 
swiftly become outdated or obsolete.
    Editorial changes and clarifications. The new introductory language 
is, ``This part establishes requirements for the preparation and 
implementation of Spill Prevention, Control, and Countermeasure (SPCC) 
Plans.'' The new language covers all SPCC requirements, both general 
and specific. That language replaces ``This part provides for * * *.'' 
The phrase ``Plans prepared in accordance with Secs. 112.7, 112.8, 
112.9, 112.10, and 112.11'' was eliminated because new introductory 
language makes it unnecessary.

Section 112.1(f)--Proposed as Sec. 112.1(g)--Plans for Exempted 
Facilities

    Background. This is a new section, proposed in 1993, that allows 
the Regional Administrators (RAs) to require preparation of entire an 
SPCC Plan, or applicable part, by the owner or operator of an otherwise 
exempted facility, that is subject to the jurisdiction of EPA under 
section 311(j) of the CWA. The proposal stems from the 1988 Interagency 
SPCC Task Force and subsequent GAO report, ``Inland Oil Spills'' (GAO/
RCED-89-65).
    Comments. Authority. One commenter called the proposal ``arbitrary 
and capricious'' and feared political use of the authority. Some 
commenters questioned EPA authority for the proposal.

[[Page 47071]]

    Standard to use authority. One commenter favored the proposal and 
suggested that we look at additional physical characteristics of the 
facility in order to make a determination to require the owner or 
operator to prepare an SPCC Plan. Other commenters asserted that the 
standards for requiring Plans need to be specified, or that ``good 
cause'' be the standard.
    Response Plans. One commenter urged a ``vastly abbreviated'' 
version of this section in the event that the Regional Administrator 
requires a small Appalachian facility to prepare a facility response 
plan in addition to an SPCC Plan, because the ``extensive requirements 
outlined in the appendices and attachments have little applicability'' 
to a small Appalachian oil field storage facility. The commenter added 
that the availability of secondary containment at most Appalachian 
facilities mitigates many of the requirements of the complete response 
plan which is directed towards large oil storage tanks.
    Appeals process. Other commenters called for an appeals process, 
and specification of time frames within which the RA must act.
    Response to comments. Authority. EPA believes that it has adequate 
authority under section 311 of the CWA to require any facility within 
its jurisdiction to prepare a Plan that could because of its location, 
cause a discharge as described in Sec. 112.1(b). This authority is 
broad enough to encompass the storage or use capacity of any exempted 
facility within EPA's jurisdiction, regardless of size.
    Standard to use authority. RAs may invoke this section to carry out 
the purposes of the Act on a case-specific basis when it is needed to 
prevent a discharge as described in Sec. 112.1(b), and thus protect the 
environment. While we expect to use this section sparingly, it is 
necessary to address gaps in other regulatory regimes that might best 
be remedied by requiring a facility to have an SPCC Plan. Factors the 
RAs may consider in making a determination that a facility needs an 
SPCC Plan include, but are not limited to, the physical characteristics 
of the facility, the presence of secondary containment, the discharge 
history of the facility, and the proximity of the facility to sensitive 
environmental areas such as wetlands, parks, or wildlife refuges. An 
example of the use of this section might be when a facility is exempted 
from SPCC rules because its storage capacity is below the regulatory 
threshold, but the facility has been the cause of repeated discharges 
as described in Sec. 112.1(b). The RA might require an entire Plan, or 
might only require a partial Plan addressing secondary containment, for 
example, to prevent future discharges as described in Sec. 112.1(b).
    Partial Plans. We clarify that the RA may require partial Plans to 
cover situations where the preparation of only a partial Plan may be 
necessary, such as to supplement an existing document other than a Plan 
or to address a particular environmental threat. The decision to 
require a Plan (or partial Plan) could be based on the presence of 
environmental concerns not adequately addressed under UST or NPDES 
regulations, or due to other relevant environmental factors. The 
section may be invoked when the RA determines it is necessary to 
``carry out the purposes of the Act.''
    The decision to require a partial Plan is separate from a decision 
to require an amendment to a Plan. In one case, the assumption is that 
a Plan doesn't exist; in the other, that an existing Plan needs 
amendment.
    Response Plans. Section 112.1(f) applies only to the total or 
partial preparation of an SPCC Plan. It does not authorize the Regional 
Administrator to require you to prepare a facility response plan. We 
have withdrawn a proposal (see 1993 proposed Sec. 112.7(d)(1)) which 
would have required you to prepare a response plan when your SPCC 
facility lacked secondary containment. Therefore, most facilities will 
incur no response planning costs. Instead, if your facility lacks 
secondary containment, you must prepare a contingency plan following 
the provisions of 40 CFR part 109, and otherwise comply with 
Sec. 112.7(d). As a result, requirements to prepare a facility response 
plan are contained solely in Sec. 112.20, and not Sec. 112.1(f).
    Appeals process. We agree that an appeals process is appropriate 
for this section. Therefore we have added a new paragraph (f)(5) to 
include such a process, and have provided time frames for the process. 
The appeals process is modeled upon current Sec. 112.4(f), which we 
reproposed in 1991 and have finalized today.
    Editorial changes and clarifications. We deleted the proposed 
requirement to ``submit'' a Plan in paragraph (f)(2), because we only 
require submission of Plans in certain circumstances, such as when 
there has been a discharge(s) as described in Sec. 112.1(b) over the 
threshold amount provided for in Sec. 112.4(a), and the RA believes 
that submission of the Plan is necessary. We do not require Plan 
submission as a general rule.

Section 112.2--Definitions

    Background. Definitions proposed in 1993 and 1999, and promulgated 
in the Facility Response Plan rule of 1994 and 2000 are reprinted in 
the rule for the convenience of the reader. No substantive changes were 
made to those definitions and they are not discussed further in this 
preamble, except where we made editorial changes in today's rule. The 
discussion for those editorial changes, and for proposed definitions 
that were not already finalized in the 1994 and 2000 FRP rule, follows.
Adverse Weather
    Editorial changes and clarifications. We have made slight editorial 
changes to this definition, none of which are substantive. In the first 
sentence, the phrase ``will be considered'' becomes ``must be 
considered.'' In the second sentence, the phrase ``as appropriate'' is 
placed in parentheses.
Alteration
    Background. In 1993, we proposed a definition of ``alteration'' in 
conjunction with the proposed rule for ensuring against brittle 
fracture. We proposed the definition of ``alteration'' to mean ``any 
work on a tank or related equipment involving cutting, burning, 
welding, or heating operations that changes the physical dimensions or 
configuration of a tank.''
    Comments. One commenter suggested that we conform the proposed 
definition of ``alteration'' with the API 653 definition, specifically 
deleting the phase ``or related equipment.''
    Response to comments. Related equipment. We agree with the 
commenter and will not include the term ``or related equipment'' in the 
definition to conform with API Standard 653, which does not include 
alterations of related equipment as a criterion for brittle fracture 
evaluation. In the preamble to the 1993 proposal, we gave examples of 
alteration that included the addition of manways and nozzles greater 
than 12-inch nominal pipe size and an increase or decrease in tank 
shell height. 58 FR 8843.
    Industry Standards. An industry standard that may be helpful in 
understanding the definition of ``alteration'' is API Standard 653, 
``Tank Inspection, Repair, Alteration, and Reconstruction.''
    Editorial changes and clarifications. ``Tank'' becomes 
``container.''
Breakout tank
    Background. We proposed this definition and the definition of 
``bulk storage tank'' in 1991 to clarify the distinction between 
facilities regulated

[[Page 47072]]

by DOT and EPA. Breakout tanks are used mainly to compensate for 
pressure surges or to control and maintain pressure through pipelines. 
They are also sometimes used for bulk storage. These tanks are 
frequently in-line, and may be regulated by EPA, DOT, or both. When a 
breakout tank is used for both storage and for pipeline control, it 
becomes in itself a ``complex,'' and is regulated as such. See the 
discussion on ``complexes'' in today's preamble at 
Sec. 112.1(d)(1)(ii).
    Comments. A number of commenters suggested that EPA adopt the DOT 
definition of breakout tank. Another commenter asked for guidance as to 
which agency, DOT or EPA, regulates such tanks.
    Response to comments. On the suggestion of commenters, EPA has 
adopted a modified version of the DOT definition in 49 CFR 195.2. This 
revision promotes consistency in the DOT and EPA definitions to aid the 
regulators and regulated community. We modified the DOT definition by 
substituting the word ``oil'' for ``hazardous liquid,'' because our 
rules apply only to oil. We also use in the definition the term 
``container'' rather than just ``tank'' to cover any type of container. 
This terminology is consistent with other terminology used in this 
rule.
    A breakout tank that is used only to relieve surges in an oil 
pipeline system or to receive and store oil transported by a pipeline 
for reinjection and continued transportation by pipeline is subject 
only to DOT jurisdiction. When that same breakout tank is used for 
other purposes, such as a process tank or as a bulk storage container, 
it is no longer solely within the definition of breakout tank, and may 
be subject to EPA or other jurisdiction with the new use.
    EPA and DOT also signed a joint memorandum dated February 4, 2000, 
clarifying regulatory jurisdiction on breakout tanks. That memorandum 
is available to the public upon request. It is also available on our 
Web site at http://www.epa.gov/oilspill under the ``What's New'' 
section.
Bulk Storage Container--Formerly Bulk Storage Tank
    Background. Along with ``breakout tank,'' we proposed this 
definition in 1991 to help clarify the distinctions between facilities 
regulated by EPA and those regulated by DOT. The proposed definition 
was originally for ``bulk storage tank.'' As explained below, we 
changed the definition to ``bulk storage container.''
    Comments. Many electric utility commenters urged that EPA 
explicitly exclude electrical equipment from the definition because 
such equipment is not bulk storage. Other commenters asked for a 
minimum size to which the definition should apply.
    Response to comments. We agree that electrical equipment is not 
bulk storage. See the above discussion on the applicability of the rule 
to electrical and other operating equipment under Sec. 112.1(b). See 
also the definition of ``bulk storage container'' in Sec. 112.2. For a 
discussion of minimum size containers to which the rule applies, see 
the discussion under Sec. 112.1(d)(2)(ii).
    Editorial changes and clarifications. ``Tank'' becomes 
``container'' because ``container'' is more accurate. Many containers 
storing oil are not tanks, but provide bulk storage. A bulk storage 
container may be either aboveground, partially buried, bunkered, or 
completely buried.
    The definition of ``bulk storage container'' adopted in today's 
rule should not be confused with the definitions of ``container'' used 
in several fire codes. Sometimes those codes limit a container to one 
below a certain size. See for example, the BOCA National Fire 
Prevention Code, section F-2302.1 (1999) and NFPA 30 section 1-6 
(1996). The definition adopted in today's rule is broader than the 
definitions in the codes in that it is not limited to a particular 
amount of storage capacity.
    We also clarify in today's rule that oil-filled electrical, 
operating, or manufacturing equipment is not a bulk storage container.
Bunkered Tank
    Background. We proposed this definition in 1991 to clarify that 
bunkered tanks are a subset of partially buried tanks, and as such, 
subject to part 112 as aboveground tanks.
    Comments. One commenter wrote that the definition is 
``undecipherable and should be rewritten.'' The commenter wrote that 
the definition should be, ``Bunkered tank means a partially buried 
tank, the portion of which lies above grade is covered with earth, 
sand, gravel, asphalt, or other material.''
    Response to comments. EPA agrees that the commenter's proposed 
definition is clearer, and we have used it with slight editorial 
changes.
    Editorial changes and clarifications. We added a sentence to the 
definition noting that bunkered tanks are a subset of aboveground 
storage containers for purposes of this part.
Completely Buried Tank--Proposed as ``Underground Storage Tank''
    Background. In 1991, we proposed adding a definition for 
``underground storage tank.'' It differed from the Underground Storage 
Tank (UST) program definition in 40 CFR part 280 because it excluded 
tanks which are partially buried or bunkered, as well as some other 
tanks or containers included within the part 280 definition, such as 
containers storing certain hazardous substances. Partially buried and 
bunkered tanks still have a potential to discharge oil into navigable 
waters, adjoining shorelines, or affecting natural resources. 
Therefore, we proposed to retain those tanks within our regulatory 
jurisdiction, while we proposed to exclude all completely buried tanks 
storing petroleum that are subject to all of the technical requirements 
of the UST program (40 CFR part 280 or a State program approved under 
40 CFR part 281).
    Comments. Consistency with the definition of underground tanks in 
40 CFR part 280. One commenter supported the proposal. A number of 
commenters thought that the definitions of underground tanks in parts 
112 and 280 should be consistent.
    Vaulted tanks. Commenters divided on whether subterranean vaulted 
tanks should be considered ASTs or USTs. The commenter opposing the 
treatment of subterranean vaulted tanks as ASTs in the UST definition 
argued that discharges from those tanks pose no threat to the 
environment or public health.
    Response to comments. Consistency with the definition of 
underground tanks in 40 CFR part 280. We disagree that the scope of the 
part 112 exclusion for underground tanks should be consistent with the 
scope of the definition of ``underground storage tank'' in part 280. 
The programs are designed for different purposes, therefore, the 
definitions used will necessarily differ. To eliminate confusion with 
the part 280 definition, we have changed the proposed part 112 
definition of ``underground storage tank'' to ``completely buried 
tank'' in this final rule.
    Part 280 includes within its UST definition tanks which have a 
volume up to ninety percent above the surface of the ground, which are 
considered aboveground tanks for part 112 purposes. Part 280 also 
regulates underground storage tanks containing hazardous substances, 
while the SPCC program regulates only facilities storing or using oil 
as defined in CWA section 311. The SPCC program regulates

[[Page 47073]]

facilities with relatively large completely buried storage capacity, 
while the bulk of facilities regulated under part 280 are small 
capacity facilities such as gasoline filling stations. The SPCC program 
also regulates other types of containers and facilities which part 280 
excludes, such as: tanks used for storing heating oil for consumptive 
use on the premises where stored; certain pipeline complexes where oil 
is stored; and, oil-water separators.
    Vaulted tanks. Aboveground vaulted tanks are clearly ASTs. While 
subterranean vaulted tanks may be completely below grade, they may not 
be completely covered with earth. Because of their design, they pose a 
threat of discharge into the environment, and are thus excluded from 
our definition of completely buried tank. Subterranean vaulted tanks 
are also excluded from the part 280 UST definition of underground tank 
if the storage tank is situated upon or above the surface of the floor 
in an underground are providing enough space for physical inspection of 
the exterior of the tank. Therefore, if subterranean tanks were 
excluded from our definition of completely buried tank, they would 
likely not be regulated at all, and thereby be likely to pose a greater 
threat to the environment.
    Other completely buried tanks excluded from the part 280 UST 
definition. Tanks in underground rooms or above the floor surface, or 
in other underground areas such as basements, cellars, mine workings, 
drifts, shafts, or tunnels are also not considered USTs for purposes of 
the part 280 definition. The purpose of the part 112 definition is to 
clarify that these are tanks that are technically underground but that, 
in a practical sense, are no different from aboveground tanks. They are 
situated so that, to the same extent as tanks aboveground, physical 
inspection for leaks is possible. Also, some of these tanks are 
designed such that in case of a discharge, oil would escape to 
navigable waters or adjoining shorelines, a result which our program 
seeks to prevent.
    Editorial changes and clarifications. The words ``completely below 
grade and * * *'' were added to the first sentence of the definition. 
The purpose of that revision was to distinguish completely buried tanks 
from partially buried and bunkered tanks, which break the grade of the 
land, but are not completely below grade. We further clarify that such 
tanks may be covered not only with earth, but with sand, gravel, 
asphalt, or other material. The clarification brings the definition 
into accord with the coverings noted in the definition of ``bunkered 
tank.'' In the second sentence, the word ``subterranean'' was deleted 
from ``subterranean vaults'' because all vaulted tanks, whether 
subterranean or aboveground, are counted as aboveground tanks for 
purposes of this rule.
Contiguous Zone
    Background. The definition of ``contiguous zone'' was proposed in 
1991 to conform with 1978 amendments to the CWA, and the 1990 
amendments to the National Oil and Hazardous Substances Pollution 
Contingency Plan (NCP) dealing with the scope of discharges. EPA 
received no substantive comments. Thus, we have finalized the proposed 
definition.
    The contiguous zone is the area that extends nine miles seaward 
from the outer limit of the territorial sea. A presidential 
proclamation of December 17, 1988 (No. 5928, 54 FR 777, January 9, 
1989) extended the territorial seas of the United States to 12 nautical 
miles from the baselines of the United States as determined in 
accordance with international law. However, the proclamation provided 
that nothing therein ``extends or otherwise alters existing federal or 
state law or any jurisdiction, rights, legal interests, or obligations 
derived therefrom * * *.''
Contract or Other Approved Means
    Editorial changes and clarifications. We corrected the title of the 
definition to read ``contract or other approved means,'' in place of 
``contract or other approved.'' We also changed some plural references 
to singular ones.
Discharge
    Background. The 1991 proposed changes to the definition of 
``discharge'' reflected changes to the statutory definition in the 1978 
amendments to the CWA. For clarity, the words ``of oil'' were added in 
the first sentence because the definition applies only to discharges of 
oil.
    Comments. One commenter asked for a clarification of the term 
``discharge.'' The commenter asked whether a drop of diesel fuel that 
fell onto the outside casing of a tank during refilling would be 
considered a ``discharge,'' even if the oil did not reach the ground. 
Other commenters recommended that the definition include at least an 
imminent danger that the spilled material would reach a navigable 
waterway. Another commenter asked EPA to exempt from the definition 
those discharges regulated under the CWA, such as National Pollutant 
Discharge Elimination System (NPDES) discharges. The rationale was that 
any potential environmental impacts of these discharges have been 
considered in the issuance of a facility's NPDES permit and there is no 
reason to subject such facilities to dual regulation.
    Response to comments. A discharge includes, but is not limited to, 
any ``spilling, leaking, pumping, pouring, emitting, emptying, or 
dumping,'' of oil. A discharge as described in Sec. 112.1(b) need not 
reach the level of an imminent danger to affected lands, waters, or 
resources to be a discharge. It includes any spilling, leaking, 
pumping, pouring, emitting, emptying, or dumping of any amount of oil 
no matter where it occurs. It may not be a reportable discharge under 
40 CFR part 110 if oil never escapes the secondary containment at the 
facility and is promptly cleaned up. If the discharge escapes secondary 
containment, it may become a discharge as described in Sec. 112.1(b), 
and if that happens, the discharge must then be reported to the 
National Response Center.
    Foreseeable or chronic point source discharges that are permitted 
under section 402 of the CWA, and that are either due to causes 
associated with the manufacturing or other commercial activities in 
which the discharger is engaged or due to the operation of the 
treatment facilities required by the NPDES permit, are to be regulated 
under the NPDES program. Other oil discharges in reportable quantities 
are subject to the requirements of section 311 of the CWA. Such spills 
or discharges are governed by section 311 even where the discharger 
holds a valid and effective NPDES permit under CWA section 402. 
Therefore, a discharge of oil to a publicly owned treatment work (POTW) 
would not be a discharge under the Sec. 112.2 definition if the 
discharge is in compliance with the provisions of the permit; or 
resulted from a circumstance identified and reviewed and made a part of 
the public record with respect to a permit issued or modified under 
section 402; or if it were a continuous or anticipated intermittent 
discharge from a point source, identified in a permit or permit 
application under section 402, which is caused by events occurring 
within the scope of relevant operating or treatment systems. 33 U.S.C. 
1321(a)(2); 40 CFR 117.12. Otherwise, the discharge is subject to the 
provisions of section 311 of the CWA as well as the unpermitted 
discharge prohibition of section 301(a) of the CWA. 33 U.S.C. 1311(a).
    Editorial changes and clarifications. We have revised the citation 
for the River and Harbor Act of 1899 so that it refers only to the U.S. 
Code, and have

[[Page 47074]]

deleted the reference to the Statutes at Large.
Facility
    Background. Because we regulate facilities in the SPCC rule, we 
proposed a definition of ``facility'' in 1991. It is based on the 
Memorandum of Understanding (MOU) between the Secretary of DOT and the 
EPA Administrator, dated November 24, 1971 (36 FR 24080). A discussion 
of the types of facilities covered is found in Appendix A to this rule.
    Comments. Facility boundaries. One commenter asked for 
clarification as to whether the facility is the petroleum storage site 
or a single tank at the site.
    Electrical or operational equipment. Utility commenters argued that 
electrical equipment is not a facility because no oil is being stored 
in the equipment.
    Buried pipelines, gathering lines, flowlines, waste treatment 
equipment. One commenter urged that buried pipelines at mining sites 
should be excluded from the definition because such pipelines are often 
put in place without recording their location. The commenter added that 
typically the lines are emptied and abandoned as part of final 
reclamation. Other commenters urged the exclusion of gathering lines 
and flowlines from the definition because of the cost of providing 
secondary containment and contingency planning for such lines. Another 
commenter protested the inclusion of waste treatment as a possible 
activity covered under the definition, and therefore the rule.
    Mobile or fixed facilities. One commenter urged that mobile 
equipment be excluded from the definition because the commenter 
believed that the SPCC Plan would otherwise have to be amended each 
time the mobile equipment is moved.
    Response to Comments. Facility boundaries. A facility includes any 
building, structure, installation, equipment, pipe or pipeline in oil 
well drilling operations, oil production, oil refining, oil storage, 
and waste treatment, or in which oil is used at a site, whether it is 
mobile or fixed. It may also include power rights of way connected to 
the facility. The extent of the facility will vary according to the 
circumstances of the site. It may be as small as a single container or 
as large as all of the structures and buildings on a site. Some 
specific factors to use in determining the extent of a facility may be 
the ownership or operation of those buildings, structures, equipment, 
installations, pipes or pipelines, or the types of activities being 
carried on at the facility.
    Electrical or operational equipment. We disagree with commenters 
who maintained that electrical equipment ``using'' oil as opposed to 
``storing'' it should not fall within the definition of ``facility'' in 
part 112. Section 311(j)(1)(C) of the CWA, which authorizes EPA to 
promulgate the SPCC rule, does not distinguish between the storage and 
the usage of oil. The section simply authorizes EPA, as delegated by 
the President, to establish ``requirements to prevent discharges of oil 
* * * from onshore and offshore facilities, and to contain such 
discharges * * *.'' 33 U.S.C. 1321(j)(1)(C). Nor do the definitions of 
``onshore facility'' or ``offshore facility'' in sections 311(a)(10) of 
the CWA distinguish between the use or storage of oil. Although the 
definition of ``facility'' in section 1001(9) of the OPA is limited by 
the ``purpose'' of the facility, no such limitation appears in CWA 
section 311. Moreover, EPA believes that although much of the 
electrical equipment may arguably ``use'' oil, in effect the oil is 
``stored'' in the equipment because it remains in the equipment for 
such long time frames. We added language to the definition to clarify 
that such types of equipment are facilities subject to the SPCC rule 
whether they are storing or using oil. Therefore, we revised the 
definition to include the words ``or in which oil is used.'' However, 
we note that a facility which contains only electrical equipment is not 
a bulk storage facility.
    Buried pipelines, gathering lines, flowlines, waste treatment 
equipment. Buried pipelines that carry oil at mining sites are part of 
a facility unless they are permanently closed as defined in Sec. 112.2. 
Such pipelines may otherwise be the source of a discharge as described 
in Sec. 112.1(b). Likewise, the same rationale applies to gathering 
lines and flowlines, and waste treatment equipment. Note that any 
facility or part thereof used exclusively for wastewater treatment and 
not to satisfy any part 112 requirement is exempted from the rule. The 
production, recovery, or recycling of oil is not considered wastewater 
treatment for purposes of the rule. See Sec. 112.1(d)(6).
    While such gathering lines, flowlines, and waste treatment 
equipment are subject to secondary containment requirements, the 
appropriate method of secondary containment is an engineering question. 
Double-walled piping may be an option, but is not required by these 
rules. The owner or operator and Professional Engineer certifying the 
Plan should consider whether pursuant to good engineering practice, 
double-walled piping is the appropriate method of secondary containment 
according to good engineering practice. In determining whether to 
install double-walled piping versus an alternative method of secondary 
containment, you could consider such factors as the additional 
effectiveness of double-walled piping in preventing discharges, the 
technical aspects of cathodically protecting any buried double-walled 
piping system, the cost of installing double-walled pipe, and the 
potential fire and safety hazards of double-walled pipes. Earthen or 
natural structures may be acceptable if they contain and prevent 
discharges as described in Sec. 112.1(b), including containment that 
prevents discharge of oil through groundwater that might cause a 
discharge as described in Sec. 112.1(b). What is practical for one 
facility, however, might not work for another.
    Mobile or fixed facilities. Either mobile or fixed equipment might 
be the source of a discharge as described in Sec. 112.1(b), and 
therefore both are included within the definition of ``facility.'' 
Section 112.3(c) of this rule already provides that it is not necessary 
to amend your Plan each time a mobile facility moves to a new site.
    Editorial changes and clarifications. In the first sentence we 
added the words ``oil gathering, oil processing, oil transfer, oil 
distribution'' to the list of activities listed. The added activities 
track the activities listed in Sec. 112.1(b). We also clarify that a 
vessel or a public vessel is not a facility or part of a facility. We 
deleted the word ``may'' in the second sentence of the definition 
regarding site-specific factors of facility boundaries, because it is 
redundant with the inclusion of the words, ``including, but not limited 
to.''
Fish and Wildlife and Sensitive Environments
    Editorial changes and clarifications. We made four editorial 
changes. We deleted the word ``either'' in the first sentence because 
it is unnecessary. ``Endangered/threatened species'' becomes 
``endangered or threatened species.'' We also deleted the colon in the 
last sentence because it is unnecessary. ``Discharges of oil'' becomes 
``discharges.''
Maximum Extent Practicable
    Editorial changes and clarifications. In the first sentence the 
phrase ``the limitations used to determine'' becomes ``within the 
limitations used to determine.'' In the beginning of second sentence, 
``It considers * * *.'' becomes ``It includes* * *.''

[[Page 47075]]

Navigable Waters
    Background. We proposed a revision of the definition of ``navigable 
waters'' in 1991. The rationale was to have the part 112 definition 
track the definition of ``navigable waters'' in 40 CFR part 110, which 
deals with the discharge of oil.
    Comments. Clarification of the meaning of navigable waters, maps. A 
number of commenters asked for a clarification of the definition of 
navigable waters because of the difficulty of determining which waters 
fall within the definition. Some asked for EPA maps to aid in this 
determination.
    Navigability, legal authority. Other commenters believed that the 
definition related to navigability. Some thought the definition was 
legally unsupportable because it is so broad. One commenter suggested 
that the term be limited to unobstructed streams that free flow at 
least fourteen consecutive days per year.
    Wetlands. Another commenter believed that the definition should not 
apply to wetlands because SPCC protections are not needed when wetlands 
are regulated under a permit program.
    Response to comments. Clarification of the meaning of navigable 
waters, maps. In this definition, we clarify what we mean by navigable 
waters by describing the characteristics of navigable waters and by 
listing examples of navigable waters. We also note in the definition 
that certain waste treatment systems are not navigable waters.
    We are unable to provide a map to identify all navigable waters 
because not all such waters have been identified on a map. However, the 
rule provides guidelines as to where such waters may be found.
    Navigability, legal authority. Navigable waters are not only waters 
on which a craft may be sailed. Navigable waters include all waters 
with a past, present, or possible future use in interstate or foreign 
commerce, including all waters subject to the ebb and flow of the tide. 
Navigable waters also include intrastate waters which could affect 
interstate or foreign commerce. The case law supports a broad 
definition of navigable waters, such as the one published today, and 
that definition does not necessarily depend on navigability in fact.
    Wetlands. We disagree that SPCC regulation of wetlands is 
redundant. The definition includes wetlands, as defined in Sec. 112.2 
and discussed below, because wetlands are waters of the United States. 
Different programs serve different purposes, and merely because an 
activity or function is regulated for one purpose (for example, NPDES) 
does not mean that regulation for another purpose is redundant. The 
purpose of a permit discharge system is waste treatment and management. 
The purpose of the SPCC rule is oil pollution prevention.
Offshore Facility
    Background. EPA proposed in 1991 to revise the definition of 
``offshore facility'' to conform with the CWA and NCP definitions.
    Comments. EPA or DOI jurisdiction. One commenter noted that if the 
definition of offshore facility is taken in context with the definition 
of navigable waters, then many facilities traditionally subject to EPA 
jurisdiction would become subject to DOI authority.
    CWA definition. Another commenter suggested that the EPA definition 
should instead be that contained in CWA section 311(a)(11).
    Response to comments. EPA or DOI jurisdiction. The 1994 Memorandum 
of Understanding between DOI, DOT, and EPA addresses the jurisdictional 
issue to which the commenter refers, transferring to EPA those non-
transportation-related offshore facilities landward of the coastline.
    CWA definition. EPA agrees with the commenter urging that the EPA 
definition track the statutory definition. The part 112 definition, 
except for minor editorial changes, is identical to the CWA definition. 
There is no difference between the substance of the part 112 definition 
and the CWA definition.
    Editorial changes and clarifications. Permanently moored vessels 
and other former transportation equipment. We also note that barges 
which store oil, and have been determined by the Coast Guard to be 
permanently moored, are no longer vessels, but storage containers that 
are part of an offshore facility. Likewise, a container, whether 
onshore or offshore, which was formerly used for transportation, such 
as a truck or railroad car, which now is used to store oil, is no 
longer used for a transportation purpose, and is a bulk storage 
container.
Oil
    Background. In 1991, EPA reprinted the definition of oil without 
suggesting any changes. In response to Edible Oil Regulatory Reform Act 
(EORRA) of 1995 (33 U.S.C. 2720) requirements, we have reworded the 
definition to include the categories of oil included in EORRA. Those 
categories are: (1) Petroleum oils, (2) animal fats and vegetable oils; 
and, (3) other non-petroleum oils and greases. Animal fats include 
fats, oils, and greases of animal origin (for example, lard and 
tallow), fish (for example, cod liver oil), or marine mammal origin 
(for example, whale oil). Vegetable oils include oils of vegetable 
origin, including oils from seeds, nuts, fruits, and kernels. Examples 
of vegetable oils include: corn oil, rapeseed oil, coconut oil, palm 
oil, soy bean oil, sunflower seed oil, cottonseed oil, and peanut oil. 
Other non-petroleum oils and greases include coal tar, creosote, 
silicon fluids, pine oil, turpentine, and tall oils. Petroleum oils 
include crude and refined petroleum products, asphalt, gasoline, fuel 
oils, mineral oils, naphtha, sludge, oil refuse, and oil mixed with 
wastes other than dredged spoil.
    EORRA requires that Federal agencies establish separate classes for 
at least these three types of oils. It further requires agencies to 
differentiate between those classes of oil in relation to their 
environmental effects, and their physical, chemical, biological, and 
other characteristics. EPA has provided new subparts within part 112 to 
facilitate differentiation between the categories of oil listed in 
EORRA. In an advance notice of proposed rulemaking, published on April 
8, 1999 (64 FR 17227), we requested ideas on how to differentiate among 
the SPCC requirements for facilities storing or using the various 
categories of oil. These ideas for further differentiation will be 
considered in a future rulemaking.
    Today's amendments to the definition and the creation of subparts 
have no effect on information collection, because we already include 
all types of oil in our information collection burden calculations. 
Similarly, the definition imposes no new requirements, because all oils 
have always been subject to the substantive requirements of the rule.
    Comments. What is oil. Several commenters favored the proposed 1991 
definition, which is identical to the current definition. Some asked 
for clarification as to its scope, particularly in reference to animal 
and vegetable oils, synthetic oils, mineral oils, and petroleum 
derivatives.
    Specific substances. Others asked about specific substances like 
aromatic hydrocarbons and asphaltic cement. One commenter asked if 
bilge water is oil.
    Authority. Some commenters suggested that EPA's authority did not 
extend beyond petroleum-based oils.
    Exclusions. Some commenters sought exclusions from the definition, 
generally based on contentions that certain oils (such as vegetable 
oils) are not harmful

[[Page 47076]]

to the environment if discharged. One commenter suggested a definition 
based on the liquidity of oil, founded on a rationale that solid or 
gaseous oils do not pose a threat to waters of the United States when 
discharged at a fixed facility. Another commenter urged that we exempt 
refined petroleum products from the definition because releases from 
many of these products are regulated by other statutes, such as the 
Solid Waste Disposal Act. One State commenter noted that animal and 
vegetable oils are not subject to regulation under that State's 
statutes regulating oil.
    Oil mixed with wastes or hazardous substances. Others asked for 
clarification as to whether mixed substances, used oil, and waste oils 
were oil.
    Part 280 definition. One commenter noted the difference in 
definitions between the part 112 definition and the definition in 40 
CFR part 280.
    Response to comments. What is oil. EPA interprets the definition of 
oil to include all types of oil, in whatever form, solid or liquid. 
That includes synthetic oils, mineral oils, vegetable oils, animal 
fats, petroleum derivatives, etc.
    Specific substances. As to certain specific substances, asphaltic 
cement is oil because it is a petroleum-based product and exhibits oil-
like characteristics. A discharge of asphaltic cement may violate 
applicable water quality standards, or cause a film or sheen or 
discoloration of the water or adjoining shorelines or cause a sludge or 
emulsion to be deposited beneath the surface of the water or upon 
adjoining shorelines. Aromatic hydrocarbons may or may not be oil, 
depending on their physical characteristics and environmental effects. 
Some aromatic hydrocarbons are hazardous substances. Bilge water that 
contains sufficient oil such that its discharge would violate the 
standards set out in 40 CFR 110.3 is considered oil. The percentage of 
oil concentration in the water is not determinative for the purpose of 
the definition or the discharge standards.
    Authority. We disagree that our authority only extends to 
petroleum-based oils. Our interpretation is consistent with 
Congressional intent as expressed in section 311(a)(1) of the CWA, 
which extends to all types of oils in any form. EPA's definition tracks 
that statutory definition. Our revised definition also reflects EORRA 
requirements for differentiation. EORRA did not expand or contract the 
universe of substances that are oils, it only required differentiation, 
when necessary, between the requirements for facilities storing or 
using different types of oil.
    Exclusions. While States may choose to regulate all oils or some 
oils, the CWA definition is designed to prevent the discharge of all 
oils.
    A definition based on liquidity would exclude solid oils, such as 
certain animal fats, a result that would be inconsistent with 
Congressional intent. Concerning gaseous oils, see our discussion on 
Highly volatile liquids below.
    While releases or discharges of some refined petroleum products may 
be regulated under the Solid Waste Disposal Act as waste products, that 
program is dedicated more to waste management, and does not regulate 
storage of non-waste oil.
    All oils, including animal fats and vegetable oils, can harm the 
environment in many ways. Oil can coat the feathers of birds, the fur 
of mammals and cause drowning and hypothermia and increased 
vulnerability to starvation and predators from lack of mobility.
    Oils can act on the epithelial tissue of fish, accumulate on gills, 
and prevent respiration. The oil coating of surface waters can 
interfere with natural processes, oxygen diffusion/reaeration and 
photosynthesis. Organisms and algae coated with oil may settle to the 
bottom with suspended solids along with other oily substances that can 
destroy benthic organisms and interfere with spawning areas.
    Oils can increase biological or chemical oxygen demand and deplete 
the water of oxygen sufficiently to kill fish and other aquatic 
organisms.
    Oils can cause starvation of fish and wildlife by coating food and 
depleting the food supply. Animals that ingest large amounts of oil 
through contaminated food or preening themselves may die as a result of 
the ingested oil. Animals can also starve because of increased energy 
demands needed to maintain body temperature when they are coated with 
oil.
    Oils can exert a direct toxic action on fish, wildlife, or their 
food supply. Oils can taint the flavor of fish for human consumption 
and cause intestinal lesions in fish from laxative properties. Tainted 
flavor of fish used for human consumption and the causation of rancid 
odors are public health or welfare concerns within the scope of our 
rules. Tainted flavor of fish used for human consumption may indicate a 
disease in the fish which could render them inedible and thus have a 
substantial impact on the fishermen who harvest them and communities 
who may rely on them for a food supply.
    Oils can foul shorelines and beaches. Oil discharges can create 
rancid odors. Rancid odors may cause both health impacts and 
environmental impacts. For example, the 1991 Wisconsin Butter Fire and 
Spill resulted in a discharge of melted butter and lard. After the 
cleanup was largely completed, the Wisconsin Department of Natural 
Resources declared as hazardous substances the thousands of gallons of 
melted butter that ran offsite and the mountain of damaged and charred 
meat products spoiling in the hot sun and creating objectionable odors. 
The Wisconsin DNR stated that these products posed an imminent threat 
to human health and the environment. 62 FR 54526.
    Highly volatile liquids. We do not consider highly volatile liquids 
that volatilize on contact with air or water, such as liquid natural 
gas, or liquid petroleum gas, to be oil. Such substances do not violate 
applicable water quality standards, do not cause a reportable film or 
sheen or discoloration upon the surface of water or adjoining 
shorelines, do not cause a sludge or emulsion to be deposited beneath 
the surface of the water or upon adjoining shorelines, and are not 
removable. Therefore, there would be no reportable discharge as 
described in 40 CFR 110.3.
    Oil mixed with wastes or hazardous substances. Oil means oil of any 
kind or in any form, including, but not limited to: fats, oils, or 
greases of animal, fish, or marine mammal origin; vegetable oils, 
including oils from seeds, nuts, fruits, or kernels; and, other oils 
and greases, including petroleum, fuel oil, sludge, synthetic oils, 
mineral oils, oil refuse, or oil mixed with wastes other than dredged 
spoil.
    Part 280 definition. The definition of petroleum in 40 CFR part 280 
is a subset of the part 112 definition of ``oil.'' The part 112 
definition of oil is broader than the part 280 definition of petroleum 
because part 112 regulates all types of oils, whereas part 280 
regulates only petroleum.
Oil drilling, production, or workover facilities (offshore)
    Background. See the definition of ``production facility,'' into 
which this definition has been merged.
Oil Production Facilities (Onshore)
    Background. See the definition of ``production facility,'' into 
which this definition has been merged.
Onshore Facility
    Background. As proposed, we deleted as unnecessary surplus the 
reference to the facility not being transportation-

[[Page 47077]]

related. There were no substantive comments.
Partially Buried Tank
    Background. In 1991, EPA proposed the definition of ``partially 
buried tank'' to clarify the distinction between partially buried tanks 
and underground storage tanks. We have renamed underground tanks in 
this rule as ``completely buried tanks,'' i.e., those tanks completely 
covered with earth. Partially buried tanks are subject to the SPCC rule 
the same as aboveground containers.
    Comments. One commenter wrote that the definition as proposed was 
``undecipherable'' and should be rewritten. That commenter suggested 
another definition for clarity. Two other commenters suggested that we 
adopt the part 280 UST definition for partially buried tank, which 
includes any tank system such as tank and piping which has a volume of 
10 percent or more beneath the surface of the ground.
    Response to comments. We agree that the definition could be clearer 
and have clarified it. We decline to adopt the part 280 UST definition 
(at 40 CFR 280.12) and to classify partially buried tanks as completely 
buried tanks, because they are not. The UST definition might also 
exclude some tanks or containers which would be covered by the SPCC 
definition. The UST definition includes tanks whose volume (including 
the volume of underground pipes connected thereto) are 10 percent or 
more beneath the surface of the ground. The SPCC definition of 
``partially buried tank'' contains no volume percentage and applies to 
any tank that is partially inserted or constructed in the ground, but 
not entirely below grade, and not completely covered with earth.
    Editorial changes and clarifications. We clarify that partially 
buried tanks may be covered not only with earth, but with sand, gravel, 
asphalt, or other material. The clarification brings the definition 
into accord with the coverings noted in the definition of ``bunkered 
tank.'' We added a sentence to the definition noting that partially 
buried tanks are considered aboveground storage containers for purposes 
of this part.
Permanently Closed
    Background. EPA proposed a definition of ``permanently closed'' in 
1991 to clarify the scope of facilities and tanks or containers 
excluded from coverage under the SPCC rule. Permanently closed 
containers are those containers which are no longer capable of storing 
or using oil. Permanently closed facilities are those facilities which 
are no longer capable of storing or using oil.
    In permanently closed containers and facilities, physical changes 
have been made so that storage capacity or use is rendered impossible. 
Therefore, the definition describes those changes which must have 
occurred before a container or facility is ``permanently closed.''
    Comments. In general. Several commenters favored the proposed 
definition. Others opposed it as unnecessary, believing that ``if a 
tank is not used for the storage of oil, it simply is not subject to 
the provisions of the SPCC regulations.'' Finally, several commenters 
suggested that the definition specifically exclude temporarily closed 
tanks.
    Waste disposal. Several commenters urged that the part of the 
proposal that dealt with waste disposal be deleted because waste 
disposal is already covered under other programs and should not be a 
concern of spill prevention unless flowable oil is part of the waste.
    Non-oil products. One commenter asked for clarification that a 
container which is no longer used for oil but is used for some non-oil 
product be considered permanently closed.
    Connecting lines. Another commenter asked for clarification as to 
the meaning of connecting lines. The commenter assumed that connecting 
lines means the sections of pipe that run between the tank and the 
nearest block valve.
    Explosive vapors. Numerous commenters urged that EPA delete any 
rules dealing with explosive vapors on the theory that such vapors are 
regulated by the Occupational Health and Safety Administration (OSHA) 
program and other programs. Many of these same commenters suggested 
that placing a sign on a tank indicating that it has been freed of gas 
is not a good safety practice because gas might subsequently build up 
within the tank with catastrophic results.
    Retroactivity. Several commenters suggested that the requirements 
for a tank to be permanently closed should not be applied retroactively 
to tanks previously removed from service. The rationale was that the 
cost would be prohibitive, although commenters did not provide specific 
cost estimates, and that it might cause confusion as to which tanks 
would have to be included in facility capacity calculations. These 
commenters also asserted that such tanks have been abandoned and empty, 
sometimes for many years, and pose no threat of discharge.
    Response to comments. In general. A definition is necessary to 
clarify when a container is permanently closed and no longer used for 
the storage of oil. Containers that are only closed temporarily may be 
returned to storage purposes and thus may present a threat of 
discharge. Therefore, they will continue to be subject to the rule.
    Waste disposal. Reference to waste disposal in accordance with 
Federal and State rules in proposed Sec. 112.2(o)(1) was deleted as 
unnecessary surplus. EPA agrees that other programs adequately handle 
waste disposal.
    Non-oil products. Containers that store products other than oil and 
never store oil, are not subject to the SPCC rule whether they are 
``permanently closed'' as defined or not. If the containers sometimes 
store oil and sometimes store non-oil products, they are subject to the 
rule.
    Connecting lines. We agree with the commenter's assumed definition 
of connecting lines. Connecting lines that have been emptied of oil, 
and have been disconnected and blanked off, are considered permanently 
closed.
    Explosive vapors. We deleted proposed Sec. 112.2(o)(2) on the 
suggestion of commenters that references to explosive vapors are an 
OSHA matter and inappropriate for EPA rules. We modified proposed 
Sec. 112.2(o)(3) to eliminate the reference to signs warning that 
``vapors above the LEL are not present,'' because the operator cannot 
guarantee that warning remains correct. To help prevent a buildup of 
explosive vapors, we have revised the definition to provide that 
ventilation valves need not be closed. We agree with commenters that a 
sign might be misleading and dangerous.
    Retroactivity. We believe that containers that have been 
permanently closed according to the standards prescribed in the rule 
qualify for the designation of ``permanently closed,'' whether they 
have been closed before or after the effective date of the rule. 
Containers that cannot meet the standards prescribed in the rule will 
not qualify as permanently closed. We disagree that the cost of such 
closure is prohibitive. We have simplified the proposal and deleted the 
proposed requirement to render the tank free of explosive vapor. 
Therefore, costs are lower. To clarify when a container has been 
closed, we have amended the rule to require that the sign noting 
closure show the date of such closure. The date of such closure must be 
noted whether it occurred before or after the effective date of this 
provision. Some States and localities require a permit for tank 
closure. A document noting a State closure inspection may serve as

[[Page 47078]]

evidence of container closure if it is dated.
    Industry standards. Industry standards that may be useful to effect 
the permanent closure of containers or facilities include: (1) National 
Fire Protection Association (NFPA) 30, ``Flammable and Combustible 
Liquids Code''; (2) Building Officials and Code Administrators 
International (BOCA), ``National Fire Prevention Code''; (3) American 
Petroleum Institute (API) Standard 2015, ``Safe Entry and Cleaning of 
Petroleum Storage Tanks''; and, (4) API Recommended Practice 1604, 
``Removal and Disposal of Used Underground Petroleum Storage Tanks.''
    Editorial changes and clarifications. ``Tank'' becomes 
``container.'' We revised the introduction to the definition to remove 
the phrase ``that has been closed'' because the definition would have 
been circular with that language. Instead the introduction references 
the events which must have occurred in order for a container to meet 
the definition.
Person
    Background. The definition of ``person'' proposed in 1991 was 
substantively unchanged from the current rule.
    Comments. We received one comment which urged that we should make 
clear that the United States is bound by every provision of these 
rules.
    Response to comments. See the discussion above (at Sec. 112.1(c)) 
for the applicability of the rule to Federal agencies and facilities.
Production Facility
    Background. The definition of ``production facility'' replaces two 
definitions in the proposed rule, i.e., Oil drilling, production, or 
workover facilities (offshore), proposed Sec. 112.2(j), and Oil 
production facilities (onshore), proposed Sec. 112.2(k). We replaced 
the two proposed definitions with the revised definition for editorial 
brevity as the proposed definitions contained many identical elements. 
This editorial effort effects no substantive changes in the 
requirements for the particular types of production facilities. Each 
facility must follow the requirements applicable to that facility, 
which is generally based on its operations, for example, a workover 
facility.
    Comments. Flowlines and gathering lines. Several commenters 
suggested that flowlines and gathering lines should be deleted from the 
definition because they believed that the installation of structures 
and equipment to prevent discharged oil from reaching navigable waters 
is not practicable for flowlines and gathering lines.
    Wells and separators. Other commenters also argued for the 
exemption of wells and separators.
    DOT definition. Another commenter urged consistency between the 
proposed EPA definition and the DOT definition found at 49 CFR 195.2.
    Single oil or gas field, single operator. One commenter asserted 
that the inclusion of the phrases ``in a single oil or gas field'' and 
``operated by a single operator'' in the definition is confounding. The 
commenter urged that the producing segment of the industry needs to be 
able to combine facilities into one SPCC Plan with an identification of 
the wells to which that Plan applies. The commenter questioned whether 
the inclusion of the word ``single'' would preclude an operator's 
ability to do so.
    Natural gas. Another commenter asked for clarification that natural 
gas processing facilities are not subject to rules for oil facilities.
    Response to comments. Flowlines and gathering lines. Wells and 
separators. EPA disagrees that flowlines and gathering lines, as well 
as wells and separators, should be excluded from the definition. These 
structures or equipment are integral parts of production facilities and 
should therefore be included in the definition. We also disagree with 
the argument that because the installation of structures and equipment 
to prevent discharges around gathering lines and flowlines may not be 
practicable, EPA will be flooded with contingency plans. First of all, 
secondary containment may be practicable. In Sec. 112.7(c), we list 
sorbent materials, drainage systems, and other equipment as possible 
forms of secondary containment systems. We realize that in many cases, 
secondary containment may not be practicable. If secondary containment 
is not practicable, you must provide in your SPCC Plan a contingency 
plan following the provisions of part 109, and otherwise comply with 
Sec. 112.7(d). We have deleted the proposed 1993 provision that would 
have required you to provide contingency plans as a matter of course to 
the Regional Administrator. Therefore, you will rarely have to submit a 
contingency plan to EPA. The contingency plan you do provide in your 
SPCC Plan when secondary containment is not practicable for flowlines 
and gathering lines should rely on strong maintenance, corrosion 
protection, testing, recordkeeping, and inspection procedures to 
prevent and quickly detect discharges from such lines. It should also 
provide for the quick availability of response equipment.
    DOT definition. We changed the proposed definition to be more 
consistent with the DOT definition, found at 49 CFR 195.2, in response 
to a commenter who urged consistency in EPA and DOT definitions. We 
added the uses of the piping and equipment detailed in DOT rule to our 
proposal, for example, ``production, extraction, recovery, lifting, 
stabilization, separation, or treating'' of oil. The terms ``separation 
equipment,'' used in the proposed definition of ``oil production 
facilities (onshore)'', and ``workover equipment,'' used in the 
proposed definition of ``oil drilling, production, or workover 
facilities (offshore)'', were combined into a generic ``equipment.'' 
However, we also modified the proposed definition to reflect EPA 
jurisdiction. We added the word ``structure,'' which was not in the DOT 
definition, to cover necessary parts of a production facility. We also 
added examples of types of piping, structures, and equipment. These 
examples are not an exclusive list of the possible piping, structures, 
or equipment covered under the definition. The new definition 
encompasses all those facilities that would have been covered under 
both former proposed definitions. As we proposed in 1991, and as in the 
current rule, we have retained geographic and ownership limitations.
    Single oil or gas field, single operator. ``A single geographical 
oil or gas field'' may consist of one or more natural formations 
containing oil. The determination of its boundaries is area-specific. 
Such formation may underlie one or many facilities, regardless of 
whether any natural or man-made physical geographical barriers on the 
surface intervene such as a mountain range, river, or road. We disagree 
that the term ``a single operator'' is confusing. An ``owner'' or 
``operator'' is defined in Sec. 112.2 as any ``person owning or 
operating an onshore facility or an offshore facility, and in the case 
of any abandoned offshore facility, the person who owned or operated or 
maintained such facility immediately prior to abandonment.'' A 
``person'' is not restricted to a single natural person. ``Person'' is 
a defined term in the rule (at Sec. 112.2) which includes an 
individual, firm, corporation, association, or partnership.
    Nothing in the definition would preclude an owner or operator from 
combining elements of a production facility into one SPCC Plan with an 
identification of the wells to which that Plan applies.

[[Page 47079]]

    Natural gas. Because natural gas is not oil, natural gas facilities 
that do not store or use oil are not covered by this rule. However, you 
should note, that drip or condensate from natural gas production is an 
oil. The storage of such drip or condensate must be included in the 
calculation of oil stored or used at the facility.
    Editorial changes and clarifications. One commenter suggested that 
the definitions proposed were ambiguous because of the use of the words 
``may include.'' We have eliminated the potential ambiguity caused by 
the words ``may include'' by revising the definition with the words 
``Production facility means.''
Regional Administrator
    Background. In 1991, we proposed a definition of ``Regional 
Administrator'' that was substantively unchanged from the current rule. 
In the final rule, we have deleted language concerning the ``designee'' 
of the EPA Regional Administrator because the language is unnecessary. 
Since the Regional Administrator has authority to delegate most 
functions, the term ``designee'' is almost always implied. When he does 
not have authority to delegate a function, the term ``designee'' is 
likewise unnecessary. We received no substantive comments.
Repair
    Background. In 1993, we proposed a definition of ``repair'' in 
conjunction with the proposed rule for brittle fracture evaluation.
    Comments. Ordinary maintenance. Two commenters asked for 
clarification of the term ``repair,'' so that it would exclude ordinary 
day-to-day maintenance activities which are conducted to maintain the 
functional integrity of the tank. Another asked that the infinitive 
``to maintain'' be deleted from the definition of repair so that 
evaluation for brittle fracture would not be required after ordinary, 
day-to-day maintenance.
    Related equipment. Another commenter suggested that we conform the 
proposed definition of ``repair'' with the API 653 definition, 
specifically deleting the phase ``or related equipment.''
    Response to comments. Ordinary maintenance. Some repairs in the 
nature of ordinary maintenance that do not weaken the integrity of the 
container might not necessitate brittle fracture evaluation. ``Repair'' 
means any work necessary to maintain or restore a container or related 
equipment to a condition suitable for safe operation. Typical examples 
of a repair that would trigger a brittle fracture evaluation include 
the removal and replacement of material (such as roof, shell, or bottom 
material, including weld metal) to maintain tank integrity; the re-
leveling or jacking of a tank shell, bottom, or roof; the addition of 
reinforcing plates to existing shell penetrations; and the repair of 
flaws, such as tears or gouges, by grinding or gouging followed by 
welding. The definition of ``repair'' also includes reconstruction. 
Reconstruction means the work necessary to reassemble a container that 
has been dismantled and relocated to a new site. We have amended the 
definition to reflect that ordinary, day-to-day maintenance that does 
not weaken the integrity of the container will not trigger the brittle 
fracture evaluation requirement.
    Related equipment. We agree with the commenter and will not include 
the term ``or related equipment'' in the definition to conform with API 
Standard 653, which does not include repairs of related equipment as a 
criterion for a brittle fracture evaluation.
    Industry standards. Industry standards that may be helpful in 
understanding the definition of repair (and reconstruction) include API 
Standard 653, ``Tank Inspection, Repair, Alteration, and 
Reconstruction.''
    Editorial changes and clarifications. ``Tank'' becomes 
``container.''
Spill Event
    Background. In 1991, we proposed to modify the definition of 
``spill event'' to correspond to the changes described in the 
applicability section of this rule (i.e., Sec. 112.1(b)) relating to 
the expanded scope of CWA jurisdiction.
    Comments. One commenter opposed the definition without explaining 
why. Several commenters argued that the definition should apply only to 
discharges to navigable waters.
    Response to comments. We have withdrawn the proposed definition of 
``spill event,'' and have also deleted the term from the rule. We take 
this action because the term is not mentioned in the CWA and is 
unnecessary. The term is unnecessary because the word ``discharge'' is 
adequate. ``Discharge'' is the term used in the CWA. A discharge as 
described in Sec. 112.1(b) is the same as a spill event. As to the 
comment on EPA jurisdiction, we disagree that our jurisdiction should 
apply only to discharges to navigable waters because the CWA 
establishes our jurisdiction beyond navigable waters (see the 
discussion under Sec. 112.1(b)), and we have the responsibility to 
protect the environment within the scope of our statutory jurisdiction.
Spill Prevention, Control, and Countermeasure Plan, SPCC Plan or Plan
    Background. In 1997, we reproposed the definition of ``SPCC Plan'' 
and withdrew the 1991 proposal. The 1997 proposal would broaden the 
acceptable formats of SPCC Plans, eliminating the requirement that the 
Plan meet the format or sequence formerly specified in the rule.
    Comments. Editorial changes and clarifications. One commenter 
suggested that the last two sentences in the proposed definition should 
be deleted because they contain substantive requirements, and relocated 
to Sec. 112.7. Another commenter thought that the SPCC definition 
should be revised to say that the Plan documents spill prevention 
measures and not compliance with the rule, because compliance is 
determined by comparing the contents of the Plan with the rules.
    Response Plan. A few commenters opposed the definition on the 
theory that it constitutes a type of response plan. Those commenters 
argued that the thrust of the definition should be on spill 
containment, not paperwork.
    Acceptable formats. Many commenters favored the proposal. Several 
suggested various formats that might qualify such as Integrated 
Contingency Plans, State Plans, Electrical Equipment Area Response 
Plans, Stormwater Pollution Prevention Plans, and others. One commenter 
thought that EPA should specify acceptable formats. Several commenters 
suggested that various formats such as Integrated Contingency Plans and 
State Plans are presumptively acceptable.
    Response to comments. Response Plan. We disagree that the proposed 
definition constitutes a ``response plan.'' The definition results in 
no substantive changes in response planning requirements.
    Acceptable formats. We agree that any equivalent prevention plan 
acceptable to the Regional Administrator qualifies as an SPCC Plan as 
long as it meets all Federal requirements (including certification by a 
Professional Engineer), and is cross-referenced from the requirement in 
part 112 to the page of the equivalent plan. We do not agree that we 
should specify acceptable formats. We will give examples of those 
acceptable formats, but those examples are not meant to be exhaustive.
    Examples of an ``equivalent prevention plan'' might be, for 
instance, an Integrated Contingency Plan (ICP), a State plan, a Best 
Management Practice Plan (which is a component of the Stormwater 
Pollution Prevention Plan),

[[Page 47080]]

or other plan that meets all the requirements of part 112 and is 
supplemented by a cross-reference section identifying the location of 
elements in part 112 to the equivalent requirement in the other plan. 
We repeat EPA's commitment to the ICP format, and encourage owners or 
operators to use it. If the equivalent prevention plan has no 
requirement that a Professional Engineer certify it, it will be 
necessary to secure proper certification from the Professional Engineer 
to comply with the SPCC rule.
    An equivalent Plan might be a Plan following the SPCC sequence in 
effect before this final rule became effective. If you choose to use 
the sequence of the rule currently in effect, you may do so, but you 
must cross-reference the requirements in the revised rule to the 
sequence used in your Plan. We have provided a table in section IV.A of 
today's preamble to help you cross-reference the requirements more 
easily. If the only change you make is the addition of cross-
referencing, you need not have a Professional Engineer certify that 
change.
    Another example of an equivalent plan might include a multi-
facility plan for operating equipment. This type of plan is intended 
for electrical utility transmission systems, electrical cable systems, 
and similar facilities which might aggregate equipment located in 
diverse areas into one plan. Examples of operating equipment containing 
oil include electrical equipment such as substations, transformers, 
capacitors, buried cable equipment, and oil circuit breakers.
    A general, multi-facility plan for operational equipment used in 
various manufacturing processes containing over the threshold amount of 
oil might also be acceptable as an SPCC Plan. Examples of operating 
equipment used in manufacturing that contains oil include small lube 
oil systems, fat traps, hydraulic power presses, hydraulic pumps, 
injection molding machines, auto boosters, certain metalworking 
machinery and associated fluid transfer systems, and oil based heaters. 
Whenever you add or remove operating equipment in your Plan that 
materially affects the potential for a discharge as described in 
Sec. 112.1(b), you must amend your Plan. 40 CFR 112.5(a).
    Multi-facility plans would include all elements required for 
individual plans. Site-specific information would be required for all 
equipment included in each plan. However, the site-specific information 
might be maintained in a separate location, such as a central office, 
or an electronic data base, as long as such information was immediately 
accessible to responders and inspectors. If you keep the information in 
an electronic data base, you must also keep a paper or other backup 
that is immediately accessible for emergency response purposes, or for 
EPA inspectors, in case the computer is not functioning. Where you 
place that site-specific information would be a question of allowable 
formatting, as is the question of what is an ``equivalent'' plan; an 
issue subject to RA discretion.
    Still another example of an equivalent plan might be a Best 
Management Practice Plan (BMP) plan prepared under an NPDES permit, if 
the plan provides protections equivalent to SPCC Plans. Not all BMP 
plans will qualify, as some BMP plans might not provide equivalent 
protection. NPDES permits without BMP plans would not qualify.
    BMP plans are additional conditions which may supplement effluent 
limitations in NPDES permits. Under section 402(a)(1) of the CWA, BMP 
plans may be imposed when the Administrator determines that such 
conditions are necessary to carry out the provisions of the Act. See 40 
CFR 122.44(k). CWA section 304(e) authorizes EPA to promulgate BMP 
plans as effluent limitations guidelines. NPDES rules provide for BMP 
plans when: authorized under section 304(e) of the CWA for the control 
of toxic pollutants and hazardous substances; numeric limitations are 
infeasible; or, the practices are reasonably necessary to achieve 
effluent limitations and standards to carry out the purposes of the 
CWA.
    Any format that contains all the required elements of an SPCC Plan 
and provides equivalent environmental protection would be presumptively 
acceptable. The final decision on what is an ``equivalent'' plan, 
however, would be at the discretion of the Regional Administrator. 
``Equivalence'' would not mean that an alternate format would be the 
mirror image of an SPCC Plan, but it would have to contain all the 
required elements of an SPCC Plan. Required elements include, but are 
not limited to, provisions for a written plan, secondary containment or 
a contingency plan following 40 CFR part 109, equivalent inspections 
and tests, security, personnel training, and certification of the plan 
by a Professional Engineer. Acceptance of an equivalent plan does not, 
however, imply any type of approval or submission process. As before, 
SPCC Plans are generally not submitted to the Regional Administrator. 
The Regional Administrator could accept an equivalent prevention plan 
if it: (1) meets all regulatory requirements in the SPCC rule; and (2) 
is supplemented by a cross-reference section identifying requirements 
listed in part 112 to the equivalent requirements in the other 
prevention plan. Partial use of other equivalent prevention plans is 
also acceptable, if the plan is supplemented by elements that meet the 
remainder of the EPA requirements contained in part 112.
    Written Plans. We agree that a ``written'' Plan might also include 
texts, graphs, charts, maps, photos, and tables, on whatever media, 
including floppy disk, CD, hard drive, and tape storage, that allows 
the document to be easily accessed, comprehended, distributed, viewed, 
updated, and printed. Whatever medium you use, however, must be readily 
accessible to response personnel in an emergency. If it is produced in 
a medium that is not readily accessible in an emergency, it must be 
also available in a medium that is. For example, a Plan might be 
electronically produced, but computers fail and may not be operable in 
an emergency. For an electronic Plan or Plan produced in some other 
medium, therefore, a backup copy must be readily available on paper. At 
least one version of the Plan should be written in English so that it 
will be readily understood by an EPA inspector.
    Editorial changes and clarifications. The word ``guidelines'' was 
replaced with ``requirements,'' as proposed in 1991. EPA agrees with 
the relocation of the last two sentences of the definition. Therefore, 
we have transferred those sentences to the introduction of Sec. 112.7, 
in order to maintain the principle that definitions should not contain 
substantive requirements. We have also changed the last sentence which 
was proposed as ``* * * provide adequate countermeasures to an oil 
spill'' to read ``* * * provide adequate countermeasures to a 
discharge.'' We agree that the Plan does not document compliance, but 
merely spill prevention measures and have deleted the sentence noting 
that the Plan documents compliance with the rules. Compliance is 
determined by comparing the contents of the Plan with the regulations.
Storage capacity
    Background. In 1991, we proposed a definition of ``storage 
capacity'' to clarify that it includes the total capacity of a 
container capable of storing oil or oil mixtures. We explained that 
because the percentage of oil in a mixture is determined by the 
operator and can be changed at will, the total capacity of a container 
is considered in determining applicability under this part, regardless 
of whether the container is filled with

[[Page 47081]]

oil or a mixture of oil and another substance, as long as a discharge 
from such container could violate the harmful quantity standards in 40 
CFR part 110.
    Comments. In general. One commenter strongly favored the proposal.
    Standard of measurement. One commenter asserted that volume was the 
proper measure of storage capacity, not total capacity. Another 
commenter suggested a ``working capacity'' standard. Other commenters 
argued that the definition should apply only to containers meeting the 
definition of a bulk storage tank, and that only the oil storage 
capacity of the container be considered. Similarly, a commenter 
asserted that the ``design capacity'' of a container is what should 
count as storage capacity because electrical equipment or other 
interior components might reduce the volume of oil capable of being 
stored.
    Exclusions--small containers; waste treatment facilities, secondary 
containment containers. Small containers. Most commenters were opposed 
to the proposed definition because they either wanted an exclusion for 
small containers or because they wanted an exclusion for containers 
containing de minimis amounts of oil. These commenters argued that 
small containers would not present a significant threat of discharge.
    Waste treatment facilities. The rationale of commenters supporting 
an exemption for waste treatment containers was that some containers 
had non-usable space at the top of the container; also some containers 
contain only trace amounts of oil. Therefore, for example, storage 
tanks used to store or treat wastewaters are likely to have to be 
considered when determining storage capacity since many wastewaters 
have incidental oil content prior to treatment. They also argued that 
the definition would subject publicly owned treatment works (POTWs) to 
the rule because tanks used to control stormwater surges might contain 
small amounts of oil from runoff from parking lots and city streets.
    Secondary containment containers. Some commenters argued that the 
definition would apply to tanks used to provide secondary containment 
when determining the storage capacity of a facility.
    Response to comments. Standard of measurement. In most instances 
the shell capacity of a container will define its storage capacity. The 
shell capacity (or nominal or gross capacity) is the amount of oil that 
a container is designed to hold. If a certain portion of a container is 
incapable of storing oil because of its integral design, for example 
electrical equipment or other interior component might take up space, 
then the shell capacity of the container is reduced to the volume the 
container might hold. When the integral design of a container has been 
altered by actions such as drilling a hole in the side of the container 
so that it cannot hold oil above that point, shell capacity remains the 
measure of storage capacity because such alteration can be altered 
again at will to restore the former storage capacity. When the 
alteration is an action such as the installation of a double bottom or 
new floor to the container, the integral design of the container has 
changed, and may result in a reduction in shell capacity. We disagree 
that operating volume should be the measurement, because the operating 
volume of a tank can be changed at will to below its shell capacity.
    The keys to the definition are the availability of the container 
for drilling, producing, gathering, storing, processing, refining, 
transferring, distributing, using, or consuming oil, and whether it is 
available for one of those uses or whether it is permanently closed. 
Containers available for one of the above described uses count towards 
storage capacity, those not used for these activities do not. Types of 
containers counted as storage capacity would include some flow-through 
separators, tanks used for ``emergency'' storage, transformers, and 
other oil-filled equipment.
    Exclusions--small containers; waste treatment facilities. Small 
containers. This definition is applicable to both large and small 
storage and use capacity. Owners or operators of small facilities above 
the regulatory threshold are subject to the rule, and need to know how 
to calculate their storage or use capacity.
    However, in the applicability section of the rule, we have excluded 
containers of less than 55 gallons from the scope of the SPCC rule, 
addressing the comments of those commenters who argued for a minimum 
container size. See Sec. 112.1(d)(5). A container above that size that 
is available for use or storage containing even small volumes of oil 
must be counted in storage capacity.
    Waste treatment facilities. We agree with the commenter that a 
facility or part thereof (except at an oil production, oil recovery, or 
oil recycling facility) used exclusively for wastewater treatment 
system and not to meet any part 112 requirement should not be 
considered storage capacity because wastewater treatment is neither use 
nor storage of oil. Therefore, we have exempted such facilities or 
parts thereof from the rule. However, note that certain parts of such 
facilities may continue to be subject to the rule. See the discussion 
under Sec. 112.1(d)(6).
    Secondary containment containers. Containers which are used for 
secondary containment and not storage or use, are not counted as 
storage capacity.
    Editorial changes and clarifications. We use the word ``container'' 
instead of ``tank or container,'' because a tank is a type of 
container. We have clarified the definition to provide that the storage 
capacity of a container is the volume of oil that the container could 
hold, and have therefore substituted the words ``shell capacity'' of 
the container for ``total capacity.'' This is merely a clarification, 
and not a substantive change. We also deleted the words ``for purposes 
of determining applicability of this part,'' because the words were 
unnecessary. We also deleted the last phrase of the proposed 
definition, ``whether the tank or container is filled with oil or a 
mixture of oil and other substances,'' because the contents of the 
container do not affect the definition of its shell capacity.
Transportation-related and non-transportation-related
    Background. In 1991, we reproposed the current definition of 
``transportation-related and non-transportation-related.'' We received 
no comments on the proposal. Therefore, we have promulgated the 
definition as proposed.
United States
    Background. In 1991, we proposed to revise the definition of 
``United States'' to conform to the definition enacted in the 1978 
amendments to the CWA. We received no comments on this proposal. 
Therefore, we have promulgated the definition as proposed.
Vessel
    Background. In 1991, we reproposed the current definition of 
vessel. We received no comments on this proposal. Therefore, we have 
promulgated the definition as proposed. We note that a barge or other 
watercraft that has been determined by the Coast Guard to be 
permanently moored to the shore, and used for storage, is no longer 
being used as a vessel, and does not fit within the definition of 
vessel. Rather, it becomes a bulk storage container counted as storage 
capacity. The same concept is found in the rules for mobile facilities 
at Sec. 112.3(c), which provides that SPCC Plans apply to mobile 
facilities only

[[Page 47082]]

``while the facility is in a fixed (non-transportation) operating 
mode.''
Wetlands
    Background. In 1991, we proposed a definition of ``wetlands'' to 
define the term as used in the definition of ``navigable waters.'' The 
definition of wetlands conforms to the definition in 40 CFR part 110 
relating to the discharge of oil.
    Comments. Several commenters opposed the definition because they 
believe that it includes a series of examples which may or may not be 
correct. They also alleged that the definition fails to implement the 
1987 U.S. Army Corps of Engineers Wetlands Manual or the documents 
implementing that Manual. Another commenter asked for EPA clarification 
of what is a wetland, given the ``vague and arguable notion of a 
wetland.''
    Response to comments. The examples listed in the definition are 
intended to help the reader with guidelines to identify wetlands. While 
the examples generally represent types of wetlands, they are not 
intended to be a categorical listing of such wetlands. There may be 
examples listed that under some circumstances do not constitute 
wetlands. We believe that the 1987 Wetlands Manual is a useful source 
material for wetlands guidance. It would be impossible to specify in a 
rule every type of situation where wetlands occur. The examples listed 
in the definition are not exclusive, but provide help in clarifying 
what may be a wetland.

Section 112.3 Introduction

    Background. We have added an introduction to Sec. 112.3 as an 
editorial device to simplify the language in the paragraphs of this 
section.

Section 112.3(a)--Time Line for Preparation and Implementation of Plans 
for Existing Facilities

    Background. In 1991, we proposed to require owners or operators of 
onshore and offshore facilities in operation 60 days after the 
effective date of this final rule to ``maintain a prepared and fully 
implemented facility SPCC Plan. . . . '' We proposed giving these 
owners or operators 60 days from the date the final rule was published 
to revise their existing Plans and implement the revisions. The 
proposed rule also reflected the expanded geographic scope of the rule 
provided by CWA amendments.
    Comments. Time period to prepare and implement a Plan. A number of 
commenters favored the proposal. Many more favored a ``phase-in'' 
period, or a longer period within which to comply. Commenters suggested 
compliance periods ranging from 60 days to 7 years. Many commenters 
clustered around the suggestion that a 6 month phase-in period be 
allowed. Many others suggested compliance by the next three-year 
review, as required by Sec. 112.5(b) at that time.
    Extensions. Several commenters asked that extensions of time to 
prepare and implement Plans be automatic if Plans must be in effect 
prior to the commencement of operations. Another suggested that 
extension requests be considered ``routine.''
    Acquired facilities. One commenter asked how we would treat 
acquired facilities, whether as new or continuing operation facilities.
    Start of operations. One commenter asked when operations start, 
stating that is not always a clearly defined time. The commenter 
suggested that instead of requiring a prepared and implemented Plan, we 
should allow that a response team be in place.
    Small facilities. One commenter asserted that the time line for 
Plan preparation and implementation was unreasonable for small 
facilities, and asked that facilities with under 10,000-gallon capacity 
be allowed to operate while developing and implementing a Plan.
    Response to comments. Time period to prepare and implement a Plan. 
We have been persuaded by commenters that a longer phase-in period than 
60 days is required for facilities currently in operation or about to 
become operational within one year after the effective date of this 
rule.
    Facilities currently in operation. For a facility in operation on 
the effective date of this rule, we changed the dates in the proposed 
rule for preparation and implementation of plans from 60 days to a 
maximum of one year to accord with the time frames in the current rule. 
The owner or operator of a facility in operation on the effective date 
of this rule will have 6 months to amend his Plan and must fully 
implement any amendment as soon as possible, but within one year of the 
effective date of the rule at the latest. The owner or operator of a 
facility which has had a discharge as described in Sec. 112.1(b), or 
reasonably could be expected to have one, already has an obligation to 
prepare and implement a Plan.
    For example, an owner or operator whose facility became operational 
four years before the effective date of this rule is the owner or 
operator of a facility currently in operation on the effective date of 
this rule. He is therefore subject to current Sec. 112.3(b), and should 
have prepared his Plan no later than three and one half years before 
the effective date of this rule, and fully implemented it no later than 
three years before the effective date of this rule. Assuming that he 
still has not prepared a Plan on the effective date of the rule, he 
must prepare and fully implement a Plan immediately that meets the 
requirements of the revised rule. He is subject to penalties for 
violation of current Sec. 112.3(b) until he does so, and the penalties 
would accrue from the time the original deadlines passed before the 
effective date of this rule. The owner or operator of a facility which 
became operational four years before the effective date of the rule, 
and who prepared and fully implemented his Plan in compliance with 
current Sec. 112.3(b), must amend his Plan within 6 months of the 
effective date of this rule to meet the requirements of the revised 
rule, and fully implement the amended Plan as soon as possible, but no 
later than one year after the effective date of the rule.
    An owner or operator whose facility became operational 7 months 
before the effective date of the rule is an owner or operator of a 
facility currently in operation and is therefore subject to current 
Sec. 112.3(b). He should have prepared his Plan one month before the 
effective date of this rule. If he did, he will have 6 months from the 
effective date of this rule to amend that Plan to meet the requirements 
of the revised rule, and must fully implement the amended Plan as soon 
as possible, but within one year of the effective date of this rule. If 
he has not prepared a Plan by the effective date of the current rule as 
required, then he must prepare and fully implement a Plan immediately 
that meets the requirements of the revised rule. He is subject to 
penalties for violation of current Sec. 112.3(b) until he does so.
    An owner or operator whose facility became operational 4 months 
before the effective date of this rule is also an owner or operator of 
a facility currently in operation on the effective date of this rule 
and therefore subject to the current rule. However, in this case, the 
6-month deadline to prepare a Plan under the current Sec. 112.3(b) has 
not yet passed. Therefore, the owner or operator is subject to the Plan 
preparation and implementation deadlines in Sec. 112.3(a) of the 
revised rule. He now has 6 months from the effective date of this rule 
to prepare a Plan that meets the requirements of this rule. If he had 
already prepared a Plan under current Sec. 112.3(b), he has 6 months 
from the effective date of this rule to amend that Plan. In either 
case, he must fully implement the Plan (or amended Plan)

[[Page 47083]]

as soon as possible after the 6-month Plan preparation deadline of this 
rule, but no later than one year after the effective date of this rule.
    The owner or operator of a facility in operation on the effective 
date of this rule who is required to have prepared or implemented an 
SPCC Plan, but has not, remains subject to penalties for violation of 
current SPCC regulations. Such owner or operator is consequently 
subject to civil penalties for a violation of current Sec. 112.3 if the 
time has expired for preparation or implementation of his Plan.
    Facilities becoming operational within one year after the effective 
date of the rule August 13, 2003. If you begin operations after the 
effective date of the rule through one year after the effective date of 
this rule August 16, 2002, you will have until one year from the 
effective date of this rule to prepare and implement your Plan. In 
other words, if the rule becomes effective on January 1, and you begin 
operations on January 2, you must prepare and implement your Plan by 
January 1 of the following year. If you begin operations on June 30, 
you still have until January 1 of the following year to prepare and 
implement your plan. If you begin operations on December 31, you still 
have until January 1 (the next day) of the following year to prepare 
and implement your Plan. The rationale for the time frame in the rule 
is that you will have had notice of the Plan preparation and 
implementation requirements from the publication date of the rule, a 
period of 30 days plus one year. In addition, you would already have 
had notice of the general requirement for preparation of an SPCC Plan 
from the current part 112 regulations. Therefore, the owner or operator 
of a facility planning to become operational within one year after the 
effective date of this rule should start working on his Plan in time to 
have it fully implemented within the year.
    New facilities. The owner or operator of a facility that becomes 
operational more than one year after the effective date of this rule 
must prepare and implement a Plan before beginning operations.
    A year phase-in period is in line with legitimate business and 
investment expectations. It allows a reasonable period of time for 
facilities to undertake necessary constructions, purchases of 
equipment, or to effect changes of procedures. And again, the general 
requirement for preparation of a Plan already exists in part 112, so 
new facilities should already have been aware of the need for a Plan.
    Extensions. While we have extended the time period for compliance, 
we understand that some facilities may still need extensions of time to 
comply. Extensions may be necessary to secure necessary manpower or 
equipment, or to construct necessary structures. If you are an owner or 
operator and an extension is necessary, you may seek one under 
Sec. 112.3(f). If no Plan amendments are necessary after you review 
today's rule, you must maintain your current Plan and cross-reference 
its elements to the redesignated requirements.
    Acquired facilities. For SPCC purposes, we consider acquired 
facilities as facilities that are already operating rather than new 
facilities because these facilities must already have SPCC Plans if 
they exceed applicable thresholds.
    Start of operations. Start of operations is when you begin to store 
or use oil at a facility. Often this may be a testing or calibration 
period prior to start up of normal operations. With the extended time 
line we have provided, no response team is required, but such a team 
may be a good engineering practice. At a minimum, you must prepare and 
implement a Plan as required by this rule.
    Small facilities. With the extended time line we have provided, all 
facilities, large or small, have adequate notice and time in which to 
prepare and implement a Plan.
    Editorial changes and clarifications. We deleted the first sentence 
of the proposed rule from the final rule because it is unnecessary. It 
is unnecessary because the obligation to have prepared a Plan is 
incurred under current section Sec. 112.3(b) for the owner or operator 
of a facility in operation before the effective date of this rule. For 
the owner or operator of a facility that becomes operational on or 
after the effective date of this rule, revised Sec. 112.3 provides the 
time period within which he must prepare and implement a Plan. The 
deleted sentence read, ``Owners or operators of onshore facilities that 
become operational after September 16, 2002, and could be reasonably be 
expected to discharge oil as described in Sec. 112.1(b)(1) of this 
part, shall prepare a facility SPCC Plan in accordance with Sec. 112.7, 
and in accordance with any of the following sections that apply to the 
facility: Secs. 112.8, 112.9, 112.10, and 112.11.''

Section 112.3(b)--Time Line for Preparation and Implementation of Plans 
for New Facilities

    Background. In 1991, we proposed that new facilities contemplating 
the start of operations be required to prepare and fully implement 
Plans before beginning operations. Our rationale was that our 
experience showed that many types of failures occur during or shortly 
following facility startup and virtually all prevention, containment, 
and countermeasure practices are a part of the facility design or 
construction.
    Comments. Many commenters suggested various phase-in periods, as 
discussed above.
    Response to comments. We believe that our original rationale is 
still correct. Experience with the implementation of this regulation 
shows that many types of failures occur during or shortly following 
startup and that virtually all prevention, containment, and 
countermeasure practices are part of the facility design or 
construction. Therefore, it can be beneficial to the environment and 
carries out the intent of the statute if a facility Plan is prepared 
and implemented before startup. However, to provide sufficient notice 
to new facilities that a Plan must be prepared and implemented before 
beginning operations, we have delayed implementation of this section 
until one year after the effective date this rule. If you begin 
operations within one year of the effective date of this rule, you must 
comply with the requirements in Sec. 112.3(a). However, if you begin 
operations more than one year after the effective date of this rule, 
your facility would be ``new'' and you would have to prepare and 
implement an SPCC Plan before you begin operations. If you need an 
extension to comply, you may seek one under Sec. 112.3(f).
    Editorial changes and clarifications. The phrase ``* * * could 
reasonably be expected to discharge oil, as described in Sec. 112.1(b) 
of this part* * *'' becomes ``could reasonably be expected to have a 
discharge as described in Sec. 112.1(b).''

Section 112.3(c)--Time Line for Preparation and Implementation of Plans 
for Mobile Facilities

    Background. In 1991, we proposed that owners or operators of 
onshore and offshore mobile facilities be required to have a prepared 
and implemented Plan before beginning operations. Since existing mobile 
facilities are a subset of existing facilities, we generally assume 
that these facilities already have a Plan in place, as the rule now 
requires. 40 CFR 112.3(c). Both new and existing mobile facilities 
would therefore have to comply with the rule requiring a fully prepared 
and implemented Plan before beginning operations.
    Comments. In general. One commenter believed that requiring Plans

[[Page 47084]]

for mobile facilities is unworkable because their physical surroundings 
are subject to change. Another commenter supported our proposal to 
allow general Plans for mobile facilities.
    Multi-well drilling programs. One commenter asked if Plan updates 
would be required in a field where a multi-well drilling program is 
underway. The commenter suggested that updates should be required only 
after the drilling program is complete.
    Response to comments. In general. We agree that the physical 
surroundings of mobile facilities are subject to change. However, we 
disagree that changing physical surroundings should exempt mobile 
facilities from the rule. Mobile facilities may have ``general'' Plans 
and need not prepare a new Plan each time the facility is moved to a 
new site. When a mobile facility is moved, it must be located and 
installed using the spill prevention practices outlined in the Plan for 
the facility.
    Mobile facilities currently in operation are assumed to have 
implemented Plans already, because they are currently legally required 
to do so. Both new and existing mobile facilities must have Plans 
prepared and fully implemented before operations may begin. If after 
your review of today's rule, you decide that no amendment to your Plan 
is necessary, except for cross-referencing, you may continue to operate 
under your existing Plan, but you must promptly cross-reference the 
provisions in the Plan to the new format. Extension requests under 
Sec. 112.3(f) are also available for mobile facilities under the proper 
conditions.
    Multi-well drilling programs. It is not necessary to amend the Plan 
every time you drill a well in a field containing multiple wells. A 
general Plan will suffice.
    Editorial changes and clarifications. We deleted the phrase ``using 
good engineering practice,'' in the third sentence of the paragraph 
because good engineering practice is required of all Plans. See the 
introduction to Sec. 112.7. Therefore, the phrase was unnecessary.

Section 112.3(d)--Certification by Professional Engineers

    Background. The current rule only requires that the Professional 
Engineer (PE), having examined the facility and being familiar with the 
provisions of part 112, attest by means of his certification that the 
Plan has been prepared in accordance with good engineering practices. 
In 1991, we proposed to add specificity to the meaning of the 
certification requirements for a PE. We proposed that the PE attest 
that he is familiar with the requirements of part 112, that he has 
visited the facility, that the Plan has been prepared in accordance 
with good engineering practice and the requirements of part 112, that 
required testing has been completed, and that the Plan is adequate for 
the facility.
    Comments. Certification requirement. Most commenters supported a 
certification requirement for PEs. Some opposed it on grounds that if 
all the components of the Plan were specified by rule, then 
certification is unnecessary. One U.S. territory, U.S. Samoa, noted 
that it doesn't register PEs, arguably making compliance with the rule 
difficult for owners or operators of facilities in Samoa.
    Other commenters thought a PE certification requirement was 
unnecessarily burdensome and costly for small facilities, but did not 
provide cost estimates. One commenter asserted that PE certification 
should not be required for small facilities, due mainly to the 
prohibitive cost. The commenter also maintained that most small 
facilities have tanks that are required by State or local law to have 
the Underwriters Laboratory Seal of Approval and to have submitted a 
detailed plan for review and approval to the fire marshal prior to 
installation.
    Certification by other environmental professionals. Several 
commenters suggested that certification could be effected by another 
environmental professional, rather than a PE, or by another 
environmental professional with PE oversight.
    Good engineering practice. One commenter noted that EPA specified 
in the 1991 preamble that the application of good engineering practice 
will require that appropriate provisions of applicable codes, 
standards, and regulations be incorporated into the SPCC Plan for a 
particular facility. 56 FR 54617-18. The commenter added, however, that 
we do not define ``good engineering practice'' for this program, and 
urged EPA to specify in more detail as to its understanding of the 
term.
    Testing. Some commenters wrote that it would be better for the PE 
to enumerate all the inspections and tests that have been completed, 
plus those that should be completed before the facility commences 
operations and those that should be undertaken periodically after it 
commences operations. A few commenters objected to the proposed 
requirement that the PE attest that required testing has been 
completed, suggesting instead that the operator is responsible for 
completion of testing. Another commenter suggested that the PE be 
allowed to attest to the presence of those written procedures which 
require testing.
    Non-technical changes. Most supported the idea that non-technical 
changes to a Plan (for example, the emergency contact list, phone 
numbers, or names) need not have PE certification.
    Time limit for PE certification. One commenter suggested a time 
limit of three years or less on PE certification, suggesting that the 
PE should be required to reinspect the premises periodically, 
preferably annually, to ascertain that the Plan continues to be 
implemented.
    PE costs. Some commenters argued that requiring an independent or 
outside PE for Plan certification would be extremely expensive for 
facilities located in remote areas. These commenters were principally 
concerned that we did not fully account for the cost to a facility 
owner or operator for a PE to visit each facility before certifying a 
Plan. Requiring the use of an independent or outside PE could be 
burdensome to facility owners or operators.
    Response to Comments. Certification requirement. PE certification 
of all facilities, both large and small, is necessary because a 
discharge as described in Sec. 112.1(b) from any size facility may be 
harmful, and PE review and certification of a Plan may help prevent 
that discharge. We disagree that PE certification is prohibitively 
costly for small facilities. A Plan certified by a PE may well save the 
owner or operator money due to improved facility operations and 
decreased likelihood of discharge, thus averting potentially costly 
cleanups. Because a Plan for a smaller facility is likely to be less 
complicated than a Plan for a larger facility, PE certification costs 
should likewise be lower for a smaller facility. In our Information 
Collection Request, estimated total costs for a new facility to prepare 
and begin implementation of a Plan, including PE certification costs, 
are $2,201 for a small facility, $2,164 for a medium facility, and 
$2,540 for a large facility. This cost is incurred only in the year 
that the facility first becomes subject to the rule. This one-time cost 
incurred by a small facility is less than 1.5 percent of the average 
annual revenue for small facilities in all industry categories. The 
cost for the PE certification alone would represent even less than 
that. As shown in Chapter 5 of the Economic Analysis for this 
rulemaking, the average annual revenue for the smallest regulated 
facilities (under the current rule) ranges from $150,000 to $6,833,000, 
depending on the industry category. For example,

[[Page 47085]]

farms with annual revenue between $100,000 and $249,999 have an average 
annual revenue per farm of $161,430, and $2,201 (the one-time cost to 
prepare and implement a Plan) represents only 1.36 percent of that 
annual revenue. Of course, under the revised rule many of these small 
facilities will not be regulated by the SPCC program at all.
    A PE's certification of a Plan means that the PE is certifying that 
the facility's equipment, design, construction, and maintenance 
procedures used to implement the Plan are in accordance with good 
engineering practices. And this is important because good engineering 
practices are likely to prevent discharges. PE certification, to be 
effective for SPCC purposes, must be completed in accordance with the 
law of the State in which the PE is working. For example, some States 
require a PE to apply his seal to effectuate a certification. Others do 
not.
    We also disagree that small facilities need not have PE 
certification for SPCC Plans when the tanks are certified by the 
Underwriters Laboratory. A Plan consists of more than a certified tank. 
It contains provisions for secondary containment, integrity testing, 
and other measures to prevent discharges. Those provisions require PE 
certification to ensure that they meet the requirements of the rule and 
that the Plan is effective to prevent discharges.
    Finally, by modifying the applicability provision in 
Sec. 112.1(d)(2), we are today exempting many small facilities from the 
requirement to prepare and implement a Plan at all, thus saving all 
prospective PE costs.
    In response to the commenter from Samoa, who noted that territory 
does not register PEs, the rule would allow an SPCC facility there to 
hire a PE licensed in some other State or U.S. territory.
    Certification by other environmental professionals. Certification 
by a PE, rather than by another environmental professional is necessary 
to ensure the application of good engineering judgment. A PE must 
obtain a Bachelor of Engineering degree from an accredited engineering 
program, pass two comprehensive national examinations, and demonstrate 
an acceptable level (usually four additional years) of engineering 
experience. A licensed engineer is also required to practice 
engineering solely within his areas of competence and to protect the 
public health, safety, and welfare. All licensed PEs, no matter who 
their employer, are required by State laws and codes of ethics to 
discharge their engineering responsibilities accurately and honestly. 
Furthermore, State governments have and do exercise the authority to 
discipline licensed PEs who fail to comply with State laws and 
requirements. Other environmental professionals may not have similar 
expertise nor be held to similar standards as the licensed PE.
    It is not always necessary for a PE to visit the facility. 
Therefore, we have revised Sec. 112.3(d) to a allow site visit by 
either the PE or his agent. Often it will be sufficient if the PE 
reviews the work of other engineering professionals who have visited 
the facility. Someone would have to visit the facility, but not 
necessarily the PE. Nevertheless, in all cases the PE must ensure that 
his certification represents an exercise of good engineering judgment. 
If that requires a personal site visit, the PE must visit the facility 
himself before certifying the Plan.
    Good engineering practice. As we noted in the 1991 preamble (at 56 
FR 54617-18), good engineering practice ``will require that appropriate 
provisions of applicable codes, standards, and regulations be 
incorporated into the SPCC Plan for a particular facility.'' We agree 
with the commenter that the rule needs more specificity in this regard. 
Therefore, we have amended Sec. 112.3(d)(1)(iii) to specifically 
include consideration of applicable industry standards as an element of 
the PE's attestation that the Plan has been prepared in accordance with 
good engineering practice. We reiterate today, as we did in 1991, that 
consideration of applicable industry standards is an essential element 
of good engineering practice. Industry standards include industry 
regulations, standards, codes, specifications, recommendations, 
recommended practices, publications, bulletins, and other materials. 
(See Sec. 112.7(a)(1) and (j).) The owner or operator must specifically 
document any industry standard used in a Plan to comply with this 
section. The documentation should include the name of the industry 
standard, and the year or edition of that standard. However, as 
discussed above, we have chosen not to incorporate specific industry 
standards into the rule.
    Testing. The proposed rule would have required the PE to certify 
that required testing was completed. We have been persuaded by comments 
that the requirement should be that procedures for inspections and 
tests have been established, not necessarily completed, because the PE 
is not normally present at time of completion. Nor do we believe it is 
necessary to impose a requirement that the PE oversee all testing 
because the PE only shares responsibility with the owner or operator 
for establishing procedures, not for their implementation, which is the 
sole responsibility of the owner or operator. However, the PE may 
include in the Plan a schedule for testing, with specific time frames 
for the completion of that testing. See also the discussion in today's 
preamble (at section IV.D.3) on ``Completion of Testing.''
    Non-technical changes. PE certification is not required for items 
that do not require engineering judgment, such as telephone numbers; 
names on lists; some, but not all, product changes (see the response to 
comments of Sec. 112.5(a)); ownership changes; or, any other changes 
not requiring engineering judgment.
    Time limit for PE certification. We disagree that there should be a 
time limit on PE certification because the rule ensures that the PE 
reviews the Plan at appropriate times. Thus, current PE certifications 
remain valid. But new certifications after the effective date of this 
rule must include the required attestations. If you are an owner or 
operator you must review your Plan at least every five years (under 
revisions made in today's rule), and amend it if new technology is 
warranted. Also, you must amend your Plan to conform with any 
applicable rule requirements, or at any time you make any change in 
facility design, construction, operation, or maintenance that 
materially affects its potential for a discharge as described in 
Sec. 112.1(b). All material amendments require PE certification. 
Therefore, because a Plan will likely require one or more amendments 
requiring PE review and certification, a time limit on PE 
certifications is unnecessary. See Sec. 112.5(c).
    Other PE issues. As to other PE issues, as noted above (see section 
IV.D.2 of this preamble), the PE need not be independent of the 
facility. Nor is there a requirement that he not have a financial 
interest in it. We believe the professional integrity of a PE and the 
professional oversight of boards licensing PEs are sufficient to 
prevent any abuses.
    It is not necessary that the PE be licensed in the same State as 
the facility because the SPCC program is national in scope and 
therefore State expertise is unnecessary. While States may prescribe 
more stringent requirements than EPA, a PE may familiarize himself with 
any particular requirements a State may impose and address them in the 
Plan. See Sec. 112.7(j). Furthermore, violations of PE ethics may be 
handled by the licensing board of the PE's state no matter where the 
work is done.
    EPA maintains that a site visit is necessary, but the visit may be 
by either the PE or his agent, so long as a visit by

[[Page 47086]]

an agent is consistent with good engineering practice. A visit by the 
PE's agent can generally be sufficient given that the PE will oversee 
and be responsible for his agent's work.
    PE costs. We note that we did not propose a requirement for an 
independent PE, but requested comments on it. In the final rule, we 
require either the PE or the PE's agent to visit and examine the 
facility before the PE certifies the Plan. An agent might include an 
engineering technician, technologist, graduate engineer, or other 
qualified person to prepare preliminary reports, studies, and 
evaluations after visiting the site. The PE, after reviewing the 
agent's work, could then legitimately certify the Plan. Also, in the 
final rule, we allow the PE to be an employee of the facility as well 
as registered in a different State than the facility is located, in 
order to approve a Plan. The rationale is that SPCC work is national in 
scope and therefore State expertise is unnecessary.
    Editorial changes and clarifications. ``Registered Professional 
Engineer'' becomes ``licensed Professional Engineer.'' The first 
sentence of the paragraph was proposed as, ``No SPCC Plan shall be 
effective to satisfy the requirements of this part unless it has been 
reviewed by a Registered Professional Engineer.'' We revised it to 
read, ``A licensed Professional Engineer must review and certify a Plan 
for it to be effective to satisfy the requirements of this part.'' This 
revision is due to the fact that PEs are licensed by States.

Section 112.3(e)--Location and Availability of Plan

    Background. In 1991, we proposed that the Plan be available at the 
facility if the facility is normally manned at least four hours a day, 
in lieu of the current requirement that the Plan be available if the 
facility is manned eight hours a day. If the facility is not attended 
at least four hours a day, the Plan would have to be available at the 
nearest field office.
    The rationale for the change is that some facilities interpreted 
the eight hour requirement not to apply to a facility that is only 
operating seven and one-half hours per day, with a half an hour 
deducted for lunch. The availability of a Plan can be extremely useful 
in preventing and mitigating discharges, therefore it must be available 
most of the time at attended facilities.
    Comments. Editorial changes and clarifications. Several commenters 
questioned the meaning of ``normal working hours,'' asking whose hours 
that meant, those of EPA or those of the facility. Several commenters 
questioned the meaning of ``nearest field office.''
    Plan availability. Several commenters favored the proposal. One 
commenter suggested that we amend the rule to provide that the Plan be 
available ``without advance notice,'' so that it would be fully 
implemented at all times, not just when an inspection is impending. One 
commenter thought that the Plan should always be located at the 
facility, whether manned or not, perhaps protected by a laminated 
cover, and at ``appropriate control centers.''
    State and local agencies. Another commenter suggested that the Plan 
be filed with the local fire department and LEPC (Local Emergency 
Planning Committee) to facilitate public review. One State suggested 
there be a Federal requirement that the Plan also be filed with the 
State.
    Response to comments. Nearest field office, normal working hours. 
The term ``nearest field office'' in paragraph (e)(1) means the office 
with operational responsibility for the facility, or the emergency 
response center for the facility, because those locations ensure 
accessibility for personnel who need to respond in case of a discharge. 
The term ``normal working hours'' in paragraph (e)(2) refers to the 
working hours of the facility or the field office, not EPA.
    Plan availability. Today we have finalized the 1991 proposal that 
the Plan must be available at the facility if it is normally attended 
at least four hours per day, or at the nearest field office if it is 
not so attended. A Plan must always be available without advance 
notice, because an inspection might not be scheduled. You are not 
required to locate a Plan at an unattended facility because of the 
difficulty that might ensue when emergency personnel try to find the 
Plan. However, you may keep a Plan at an unattended facility. If you do 
not locate the Plan at the facility, you must locate it at the nearest 
field office.
    State and local agencies. You are not required to file or locate a 
Plan with a State Emergency Response Commission or Local Emergency 
Planning Committee or other State or local agency because the 
distribution would unjustifiably increase the information collection 
burden of the rule, and not all committees or agencies may want copies 
of SPCC Plans. Should a State wish to require filing of a Federal SPCC 
Plan with a State or local committee or agency, it may do so. No 
Federal requirement is necessary.
    Editorial changes and clarifications. In paragraph (e)(2), we 
deleted the term ``or authorized representative'' after ``Regional 
Administrator,'' because the Regional Administrator may delegate his 
duties. Therefore, the term is unnecessary.

Section 112.3(f)--Extension of Time

    Background. In 1991, we proposed to allow only new facilities to 
apply for extensions of time to comply with the requirements of part 
112. The current rule allows any facility to apply for an extension, 
including existing fixed and mobile facilities. The rationale for 
limiting extension requests to new facilities was that existing fixed 
and mobile facilities have had since 1974 to comply with the rule.
    Comments. Automatic extensions. Several commenters suggested that 
we automatically grant extension requests if we are to require a Plan 
to be in effect prior to commencement of operations.
    Existing Plan requirements. Another commenter criticized the 
proposed requirement to submit the existing Plan with each extension 
request, because EPA's review of the Plan cannot practically be an 
element of the extension granting process. Another commenter suggested 
that the language in paragraph (f)(3) would be better if it said that 
the existing Plan's provisions remain in effect until they are 
superseded by changes proposed by the facility, because these words 
better reflect the intention of the rule.
    Amendments. Several commenters urged EPA to allow extensions for 
preparation and implementation of Plan amendments.
    Response to comments. Automatic extensions. Automatic extension 
requests are not justifiable because we have extended the time within 
which most facilities have to prepare and implement Plans. See 
Sec. 112.3(a), (b), and (c). Also, under the revised rule, you may 
request an extension for the preparation and implementation of any 
Plan, or amendment to any Plan. See Sec. 112.3(f).
    Existing Plan requirements. We have broadened the scope of 
extension requests to any facility that can justify the request, 
because for every type of facility there may be cases in which an 
extension can be justified. Existing fixed and mobile facilities may 
experience delays in construction or equipment delivery or may lack 
qualified personnel, and these circumstances may be beyond the control 
of, and without the fault of, the owner or operator. We also agree with 
the commenter that the submission of the entire Plan as a matter of 
course is unnecessary to evaluate each extension request. Therefore, we 
have amended the rule to provide that the Regional Administrator may 
request your Plan if he deems it appropriate. But we do not believe 
that he will

[[Page 47087]]

always do so. It may be necessary under some circumstances. The 
Regional Administrator also retains discretion to request the Plan 
after on-site review, or after certain discharges. See Sec. 112.4(a)(9) 
and (d). We disagree with the commenter's proposed rewrite of the owner 
or operator's obligations while the request is pending because the 
better policy is to require compliance with the rest of the rule that 
is not affected by the extension request, rather than saying that the 
existing Plan continues in effect.
    Amendments. We have also added a provision for an extension of time 
to prepare and implement an amendment to the Plan, as well as an entire 
Plan. We believe that there may be cases in which an extension can be 
justified for a Plan amendment because the same extenuating 
circumstances may apply.
    Editorial changes and clarifications. In paragraph (f)(3), ``letter 
of request'' becomes ``written extension request.'' In the last 
sentence of that paragraph, ``with respect to'' becomes ``related to.''

Section 112.4(a)--Reporting Certain Discharges to EPA

    Background. In 1991, we proposed to require more information than 
is currently required in the rule for reporting certain discharges. If 
your facility discharged more than 1,000 gallons in a discharge as 
described in Sec. 112.1(b), or discharged oil in quantities that may be 
harmful in more than two discharges as described in Sec. 112.1(b) 
within any consecutive twelve month period, you would have been 
required to submit certain information to the Regional Administrator.
    In 1993, we proposed a modification to Sec. 112.4(d)(1) which would 
allow the Regional Administrator to require the submission of the 
listed information in Sec. 112.4(a)(1) at any time, whether or not 
there had been a discharge as described in Sec. 112.1(b).
    In 1997, we proposed a reduction of the amount of information 
currently required by Sec. 112.4(a). We proposed to eliminate the 
following information, unless the Regional Administrator specifically 
requested it: (1) The date and year of initial facility operation; (2) 
maximum storage or handling capacity of the facility and normal daily 
throughput; and, (3) a complete copy of the SPCC Plan with any 
amendments.
    Comments. In general. Most commenters favored the 1997 proposal. 
Several commenters opposed the proposal.
    Information submission at any time. One commenter argued that the 
1993 proposal allowing EPA to require submission of the information 
required in Sec. 112.4(a)(1) and to require Plan amendments at any time 
is vague and does not provide adequate notice to the regulated 
community.
    Submission of entire Plan. One commenter thought that meaningful 
review of the information submitted was impossible without the entire 
Plan. Two commenters believed that EPA would always request the 
information it proposed to eliminate.
    Discharge threshold. Other commenters proposed a higher threshold 
for having to report a discharge than is currently required by 
Sec. 112.4(a). Those thresholds ranged from 25-55 gallons. One 
commenter suggested that we relax the reporting requirement for very 
minor releases of petroleum products. Another suggested that if the 
discharge causes a sheen that dissipates within 24 hours, there should 
be no obligation to report.
    Maps, flow diagrams, and charts. Several commenters suggested that 
we eliminate the requirement to submit maps, flow diagrams, and charts 
because those documents ``add nothing useful to the inquiry.''
    Off-site category. Another commenter suggested that we create an 
``off-site'' category of spill reports for discharges reported by a 
facility that are in a water body adjacent to the reporter's facility, 
or for discharges that originate off-site, but migrate to the facility.
    Calculation of time for discharge reports required by 
Sec. 112.4(a). Several commenters suggested that we calculate the time 
for the submission of discharge reports required by Sec. 112.4(a) on a 
``block'' basis, rather than a ``rolling'' basis.

Response to Comments

    Information submission at any time. We agree with the commenter 
that the 1993 proposal to give the Regional Administrator authority to 
require submission of the requested information in this section at any 
time is vague, and have therefore withdrawn that part of the proposal. 
We will only require such information after the discharges specified in 
this section.
    Submission of entire Plan. CWA section 311(m) provides EPA with the 
authority to require an owner or operator of a facility subject to 
section 311 to make reports and provide information to carry out the 
objectives of section 311; and CWA section 308(a) provides us with 
authority to require the owner or operator of any ``point source'' to 
make such reports as the Administrator may reasonably require. 
Therefore, we disagree that submission of the entire Plan is always 
necessary when reporting discharges under Sec. 112.4(a). We believe the 
information now required to be submitted is adequate to assess the 
cause of discharge and the ability of the facility to prevent future 
discharges. If the RA believes that the entire Plan has utility, he can 
request it. However, we disagree that RAs will always require 
submission of the Plan, or other information not required, as a matter 
of course. RAs may use their administrative discretion not to require 
the submission of Plan information or other additional information.
    Discharge threshold. 42 gallons. We agree that a higher threshold 
of reporting discharges is justifiable because we believe that only 
larger discharges should trigger an EPA obligation to review a 
facility's prevention efforts. We also agree that a higher threshold 
should trigger a facility's obligation to submit information and 
possibly have to take further prevention measures. Therefore, we have 
changed the threshold for reporting after two discharges as described 
in Sec. 112.1(b). Under the revised rule, if you are the owner or 
operator of a facility subject to this part, you must only submit the 
required information when in any twelve month period there have been 
two discharges as described in Sec. 112.1(b), in each of which more 
than 42 U.S. gallons, or one barrel, has been discharged. We adopted 
the 42 gallon threshold on a commenter's suggestion. We believe that a 
42 gallon threshold is the appropriate one to trigger a facility's 
information and possibly to have to take further prevention measures. 
When multiple discharges occur at a facility subject to the SPCC 
program, such as a generating station, they often involve the discharge 
of very small amounts of oil, and these discharges tend to come 
randomly from a lube pipe, an oil level sight glass crack, or some 
other apparatus, and do not normally indicate a recurring problem with 
the container. Having two or more of these small discharges does not 
indicate that the facility's SPCC Plan requires revision. The other 
reporting threshold of 1,000 gallons in any a single discharge as 
described in Sec. 112.1(b) remains the same.
    We disagree that a sheen caused by a discharge as described in 
Sec. 112.1(b) over the threshold amount that disappears within 24 hours 
should not require submission of information. The discharge itself may 
indicate a serious problem at the facility which needs to be corrected. 
The discharge report may give us the information necessary to require 
specific correction measures.

[[Page 47088]]

    ``Sheen'' rule. The duty imposed by the CWA to report to the 
National Response Center all discharges that may be harmful, further 
described by 40 CFR 110.3, is unchanged. Those discharges include 
discharges that violate applicable water quality standards; or, cause a 
film or sheen upon or discoloration of the surface of the water or 
adjoining shorelines or cause a sludge or emulsion to be deposited 
beneath the surface of the water or upon adjoining shorelines.
    Maps, flow diagrams, and charts. In response to comments which 
questioned the usefulness of such information, we have modified the 
provision regarding maps, flow diagrams, topographical maps (now 
required by paragraph (a)(6) of the current rule) to clarify that only 
the information necessary to adequately describe the facility and 
discharge, such as maps, flow diagrams, or topographical maps is 
necessary--not necessarily all of the information listed in the 
paragraph. To effect this change, we added the words ``as necessary'' 
after ``topographical maps.'' ``As necessary'' means as determined by 
the owner or operator, subject to the obligations of this rule, unless 
the RA requests more information. There might be circumstances in which 
the owner or operator would submit only a brief description of the 
facility or a map, for example, because flow diagrams and topographical 
maps were unnecessary to describe the discharge, and would not help the 
RA to determine whether any amendment to the Plan was necessary to 
prevent future discharges as described in Sec. 112.1(b).
    Off-site category. There is no necessity for an ``off-site'' 
category of discharges as described in Sec. 112.1(b) because only a 
discharge as described in Sec. 112.1(b) that originates in a facility 
subject to this part counts for purposes of Sec. 112.4(a).
    Calculation of time for discharge reports required by 
Sec. 112.4(a). We believe a ``rolling'' basis is the appropriate method 
to calculate a discharge as described in Sec. 112.1(b) for purposes of 
the rule because discharges as described in Sec. 112.1(b) that are 
closer in time are more likely to be related in cause. Discharges that 
are more proximate in time may indicate a problem that needs to be 
remedied. A ``rolling basis'' means that each discharge as described in 
Sec. 112.1(b) triggers the start of a new twelve month period. For 
example, if discharge 1 occurred on January 1, and if 
discharge 2 occurred on June 2, discharge 2 would 
trigger the regulatory submission and would start a new twelve month 
period. If discharge 3 occurred on the following February 3, 
it would again trigger a submission, because discharge 3 would 
be within 12 months of discharge 2. While the ``rolling 
basis'' would trigger more regulatory submissions than the ``block 
basis,'' we believe that it would enhance environmental protection 
because it would call potential problems to the attention of the 
Regional Administrator sooner, and allow them to be remedied sooner by 
a Plan amendment where necessary.
    ``Block'' basis. The other approach would be to use a ``block'' 
period. Under this type of calculation, each third discharge as 
described in Sec. 112.1(b) would not trigger a submission if it 
occurred within 12 months of discharge 2, but it would start 
the beginning of a new 12 month period. For example, if discharge 
1 occurred on January 1, and discharge 2 on June 2, 
discharge 2 would trigger a submission. Discharge 3 
on the following February 3 would not trigger a submission, but would 
start a new 12 month period. The principal justification for block 
reporting is also that discharges more closely related in time are more 
likely to be related. Our concern with this method is that if the 
February 3 discharge (i.e., discharge 3) is within twelve 
months of discharge 2, this situation could indicate that 
there is a problem that has not been remedied, so the February 3 
discharge should trigger a reporting submission.
    Maximum storage or handling capacity. In 1997, we proposed deletion 
of current paragraph (5) (renumbered as paragraph (4) in today's final 
rule), concerning the maximum storage or handling capacity of the 
facility and normal daily throughput. We have reconsidered this 
proposal and decided to withdraw it because the referenced information 
is necessary information. We have therefore retained the language in 
the rule. Storage capacity and normal daily throughput are important 
indicators of the impact of a potential discharge as described in 
Sec. 112.1(b).
    Additional information. If the Regional Administrator requires 
other information, for example, concerning the spill pathway, or any 
response measures taken, this request is authorized under renumbered 
Sec. 112.4(a)(9), current Sec. 112.4(a)(11).
    Adjoining shorelines, natural resources, affected natural 
resources. Discharges into navigable waters are not the only discharges 
reportable for purposes of this section. We note that any discharge as 
described in Sec. 112.1(b) is also within the scope of this section's 
reportable discharges.
    Editorial changes and clarifications. If a particular information 
request is inapplicable, you may omit it, but must explain why it is 
inapplicable. Several plural nouns like ``names'' and ``causes'' become 
singular. Wherever the phrase ``and/or'' appears, we have revised the 
phrase to read ``and.'' In 1997's proposed Sec. 112.4(a)(6), 
redesignated as Sec. 112.4(a)(7), ``spill'' becomes ``discharge as 
described in Sec. 112.1(b).'' In 1997's proposed Sec. 112.4(a)(8), 
redesignated as Sec. 112.4(a)(9), ``spill event'' becomes 
``discharge.''

Section 112.4(b)--Applicability of Sec. 112.4

    Background. Under current Sec. 112.4(b), the Sec. 112.4 
requirements for spill reporting do not apply until the expiration of 
the time permitted for the preparation and implementation of a Plan 
pursuant to Sec. 112.3(a), (b), (c), and (f). In 1991, we proposed that 
Sec. 112.4 would not apply until the expiration of the time permitted 
for the preparation and implementation of a Plan under Sec. 112.3(f) 
only. Section 112.3(f) is the time period in which you are permitted to 
prepare and implement a Plan under an extension request.
    We proposed to delete the references to Sec. 112.3(a), (b) and (c) 
because the current time periods allowed in these paragraphs for the 
preparation and implementation of the Plan (before commencement of 
operation for new facilities or mobile facilities, or after the 
effective date of the rule for other existing facilities) were proposed 
for deletion. Because future facilities would generally have a Plan 
prepared and implemented before beginning operations, there was no 
longer a need to temporarily relieve facilities of spill reporting 
obligations under Sec. 112.4(a), unless the Regional Administrator 
granted an extension under Sec. 112.3(f) to prepare and implement a 
Plan. We received no comments on this proposal.
    In today's rule, however, we have revised Sec. 112.3 to extend the 
time lines for certain facilities to prepare and implement Plans. To 
accord with this change, we are maintaining the approach under current 
Sec. 112.4(b) to provide that the Sec. 112.4 spill reporting 
requirements will not apply until the expiration of the time permitted 
for the initial preparation and implementation of a Plan under 
Sec. 112.3(a), (b), (c), and (f). Today, we have also revised 
Sec. 112.3(a) to provide an extended time line for preparing a Plan 
amendment and Sec. 112.3(f) to provide for an extension request for an 
amendment to a Plan. Therefore, we have also revised Sec. 112.4(b) to 
provide that the obligation to submit information as required by

[[Page 47089]]

Sec. 112.4(a) does not arise until the expiration of the time permitted 
for the initial preparation and implementation of the Plan under 
Sec. 112.3, but not for any amendments to the Plan. We did not 
previously propose to relieve facilities of Sec. 112.4 reporting 
requirements during Plan amendments or extensions for Plan amendments. 
An amendment may or may not be directly related to the cause of the 
discharge as described in Sec. 112.1(b), and therefore may have little 
relevance to the duty to submit discharge reports to EPA.

Section 112.4(c)--Supplying Discharge Information to the States

    Background. In 1991, we proposed that you must provide the same 
discharge information that you submit to the Regional Administrator 
under Sec. 112.4(a) to the State agency in charge of oil pollution 
control activities. The current rules require that you provide that 
information to the State agency in charge of water pollution control 
activities.
    Comments. Legal authority. One commenter suggested that we have no 
legal authority for the proposal. Another commenter asserted that EPA 
could only implement State agency recommendations if those 
recommendations fell within the scope of the SPCC rule.
    In general. Several commenters suggested the proposal was redundant 
and unnecessary, because only EPA regulates the SPCC program, not the 
States.
    State agency review. One commenter, a State, favored the proposal 
and noted that more than one State agency has statutory jurisdiction 
over oil pollution control in that State. That State and another 
suggested that all relevant State agencies receive the information. One 
commenter suggested that EPA should identify the appropriate State 
agency to which notice is due. One commenter thought the proposed 
change was misleading. Another commenter, a State, suggested that EPA 
provide the States money to review the submitted discharge information.
    Response to comments. Legal authority. We have ample legal 
authority to finalize this rule. A similar rule has been in effect 
since 1974. Section 311(j)(1) of the CWA authorizes the Federal 
government (and EPA through delegation) to establish ``procedures, 
methods, and equipment and other requirements for equipment to prevent 
discharges of oil. * * *'' Section 112.4(c) of this rule is a procedure 
to help prevent discharges that fall within the scope of that statutory 
provision. It enables States to learn of discharges reported to EPA and 
to make recommendations as to further procedures, methods, equipment, 
and other requirements that might prevent such discharges at the 
reporting facility.
    We can only implement State agency suggestions that are within the 
scope of our authority under section 311 of the CWA.
    In general. The commenter is correct that the SPCC program is a 
Federal program, but we believe that in working with the States, we can 
improve the Federal program through coordination with State oil 
pollution prevention programs. Therefore, we believe that the 
information provided to States is neither redundant nor unnecessary. 
Nor is the section misleading; it clearly states the obligation of the 
owner or operator.
    State agency review. We modified the 1991 proposal on the 
commenters' suggestion to include notice to any appropriate State 
agency in charge of oil pollution control activities, since there may 
be more than one such agency in some States and all may have need for 
the information. We do not list such agencies in the rule, as a 
commenter suggested, because the names and jurisdiction of the State 
agencies are subject to change. It is the reporter's obligation to 
learn which State agencies receive the discharge reports. Most States 
publish documents on an ongoing basis, similar to the Federal Register, 
which publicize relevant regulatory information.
    We do not provide State agencies funds to review these discharge 
reports due to budgetary constraints. While we assume that many States 
review these reports carefully, we cannot require them to do so. Thus, 
this action is not an unfunded mandate from the Federal government to 
the States. But if States do review the reports, they do so at their 
own expense.
    Editorial changes and clarifications. In the last sentence of the 
paragraph, ``discharges of oil'' becomes ``discharges.''

Section 112.4(d)--Amendment of Plans Required by the Regional 
Administrator

    Background. In 1991, we proposed that after review of materials 
under 112.4(a), the Regional Administrator (RA) might require amendment 
of the SPCC Plan. We also proposed that the RA might require Plan 
amendment after reviewing contingency plan materials submitted for 
approval. See proposed Sec. 112.7(d), 1991.
    In 1993, we proposed that the RA would also have authority to 
require Plan amendment after on-site review of the Plan. In addition, 
we proposed a clause empowering the RA to approve the Plan or require 
amendment.
    We also proposed in 1993 allowing the RA to require submission of 
the information listed in Sec. 112.4(a) at any time. The rationale to 
get this information was to prevent discharges from happening, in 
addition to seeking to correct the conditions that may have caused the 
discharge. See the background and response to comments under 
Sec. 112.4(a) for a discussion of this proposal.
    Comments. Regional Administrator approval of Plans. Several 
commenters criticized the idea of RA approval of the Plan on the theory 
that it is an unwarranted intrusion into the manner in which operators 
do business. Another urged an appeal process if EPA approval of Plans 
is required.
    Plan information and amendments. One commenter argued that allowing 
EPA to require submission of the information required in Sec. 112.4(a) 
at any time and to require Plan amendments at any time is vague and 
does not provide adequate notice to the regulated community. Several 
commenters were concerned that EPA would inconsistently require overly 
stringent measures in some Plans or might require amendments unrelated 
to discharge potential or which were financially unreasonable. Two 
commenters urged a time limit on EPA decision making following 
submission of required information. Another commenter was concerned 
that no provision required PE certification of amendments required by 
EPA.
    Response to comments. Regional Administrator approval of Plans. We 
have deleted the provision that would have allowed RA approval of 
Plans. We have decided not to create a new class of SPCC Plans which 
require EPA approval, either Plans submitted following certain 
discharges as required by Sec. 112.4(a) or Plans with contingency 
plans, because we do not believe such approval is necessary in order to 
ensure effective Plans.
    Plan information and amendments. We agree that allowing EPA to 
require submission of the information required in Sec. 112.4(a) at any 
time, and thereafter to require Plan amendments, is vague, and 
therefore we have withdrawn that part of the proposal. Furthermore, it 
is unnecessary because sections 308 and 311(m) of the CWA already 
provides us with adequate authority to request necessary Plan 
information.
    While the RA will not have authority under this section to approve 
Plans, he has authority to require Plan amendment. We will strive to be 
as timely as possible in reviewing the

[[Page 47090]]

information when submitted, and making decisions on any required 
amendments. A time limit on the RA's decision making authority would be 
unnecessary because a facility may continue to operate under its 
existing Plan while the RA's decision is pending. While we will 
consider cost in our decision making, amendments may be required on a 
case-specific basis to help prevent discharges. Any technical amendment 
required would require PE certification. See Sec. 112.5(c) .
    Editorial changes and clarifications. We have deleted reference to 
the RA's approval of the submitted Plan in proposed paragraph (d)(2), 
because the RA will not have authority to approve a Plan. He does, 
however, have authority to require Plan amendment under today's 
revision of Sec. 112.4(d).

Section 112.4(e)--Notification and Implementation of Required 
Amendments

    Background. In 1991, we reproposed the current notification 
provision concerning required Plan amendments, and the time lines for 
implementation of those amendments.
    Comments. Who receives notice. One commenter wanted EPA to notify 
railroads directly, instead of their registered agents, because of the 
time lag that might occur between the time the agent received notice 
and the owner or operator of the facility received notice. Another 
commenter urged that we also provide notice to the facility operator, 
the facility improvement owner, and the facility landowner. His 
rationale for such expanded notice was that a major problem may be 
addressed by the operator or EPA, without the knowledge and/or consent 
of the facility improvements owner and the facility landowner.
    Appeals procedure. One commenter suggested that we include a 
reference to the appeal procedure for amendments in this section.
    Response to comments. Who receives notice. In reply to the railroad 
commenter, the rule requires notice only to the owner or operator of 
the facility, and the registered agent, if any and if known. Notice 
from EPA to the facility improvements owner and landowner is 
unnecessary because these matters can and should be handled between the 
facility owner or operator and the owner or operator of the 
improvements or the landowner.
    Appeals procedure. We have not included a reference to the appeals 
procedures for required amendments in this section because the appeals 
procedures follow immediately in the next paragraph, making such 
reference redundant.
    Editorial changes and clarifications. We have changed the proposed 
requirement to mail a copy of the notice to the registered agent of a 
corporation to a requirement that such notice be effected only if the 
registered agent is known to EPA. The notification requirement for 
registered agents now tracks the notification requirement for 
registered agents in Sec. 112.1(f). Because we have withdrawn the 
proposed requirement that a corporation submit that agent's name or 
address in the submission of information required by Sec. 112.4(a), 
such agent may not be known to EPA. In the last sentence of the final 
rule, ``amendment of the Plan'' becomes ``amended Plan.''

Section 112.4(f)--Appeals of Required Amendments

    Background. In 1991, we reproposed the current appeals procedures 
for required Plan amendments. We received no substantive comments. 
Therefore, we have promulgated the procedures as proposed.
    Editorial changes and clarifications. We deleted language 
concerning the ``designee'' of the EPA Administrator because it is 
unnecessary. Current delegations allow the Administrator to delegate 
this function.

Section 112.5(a)--Plan Amendment by an Owner or Operator

    Background. In 1991, we proposed to require that an owner or 
operator amend the Plan before making any change in facility design, 
construction, operation, or maintenance materially affecting the 
facility's potential for the discharge of oil into the waters of the 
United States unless the RA granted an extension. We also listed some 
examples of facility changes which would require Plan amendment, noting 
that these examples were not an exclusive list.
    Comments. When amendment is necessary. Several commenters favored 
the proposal. Others provided differing standards for amending Plans. A 
number of commenters suggested that no amendments should be necessary 
when a facility change results in a decrease in the volume stored or a 
decrease in the potential for an oil spill. Another suggested a 
standard that amendments should be made ``when there are indicia of 
problems.'' A commenter suggested a standard that no amendments would 
be required except for those changes which would cause the spill 
potential to exceed the Plan's capabilities because day-to-day changes 
do not affect the worst case spill and the Plan should not have to be 
amended on a day-to-day basis. One commenter suggested that small 
facilities with less than 5,000 gallon-capacity should be exempted from 
the need to amend their Plans for the listed acts. Another commenter 
asserted that instead of being required to amend their Plans before 
changes are made, operators should be encouraged to incorporate new 
procedures into their SPCC Plans to prevent and contain potential 
discharges which might result from performing needed repairs and 
replacements. The rationale for the suggestion was that operators will 
then not ``save up'' potential amendments due to the burden of 
preparing an amendment.
    Material changes. Many commenters offered opinions on the examples 
of material changes listed in the rule for which amendments would be 
required. Some suggested that the rule should read that these are only 
examples of changes that may trigger amendment. Several commenters 
suggested that decommissioning a tank should not trigger an amendment 
because ``as a tank is removed, so is the requirement for an SPCC 
Plan.'' Another commenter noted that changing a product in a tank or 
cleaning a tank should not be considered commissioning or 
decommissioning a tank. One commenter suggested that an amendment to 
the Plan should be required when there is a change of product stored 
within the tank.
    Documenting no change or certain activities. Another commenter 
suggested that a log book might be used instead of a Plan amendment to 
document ``routine activities'' and measures taken to maintain the 
spill prevention and response integrity of the facility. Several 
commenters suggested that an identical replacement of tanks or other 
equipment should not be considered a material change and therefore 
amendment should not be required. A utility commenter asked that 
facilities be allowed to accumulate minor modifications for a period of 
6 months, then update the Plan.
    EPA approval. Another commenter suggested that we clarify that EPA 
approval of an amendment made under this section is not required.
    Time line for amendment implementation. Numerous commenters opposed 
the proposed requirement that a Plan be amended before any material 
changes are made. Commenters suggested various alternative amendment 
time lines ranging from 90 days to six months following such changes, 
with a cluster of commenters around the six months alternative. Others 
suggested that the Plan be

[[Page 47091]]

amended at fixed time points such as before a design is physically 
implemented, before startup of operations, after modifications, before 
new or modified equipment is in operation, or when changes are made. 
One commenter said that rule language should be clarified to note that 
the RA may specify a time period longer than six months to implement an 
amendment.
    Response to comments. When amendment is necessary. We agree with 
the commenter who suggested that we maintain the current standard for 
amendments, i.e., when there is a change that materially affects the 
facility's potential to discharge oil. This position accords with our 
stance on when Plans should be prepared and implemented. See 
Sec. 112.3. The other suggested standards too narrowly limit the 
changes which would trigger Plan amendment. We believe that an 
amendment is necessary when a facility change results in a decrease in 
the volume stored or a decrease in the potential for an oil spill 
because EPA needs this information to determine compliance with the 
rule. For example, the amount of secondary containment required depends 
on the storage capacity of a container. Decreases might also affect the 
way a facility plans emergency response measures and training 
procedures. A lesser capacity might require different response measures 
than a larger capacity. The training of employees might be affected 
because the operation and maintenance of the facility might be affected 
by a lesser storage capacity.
    Likewise, a standard requiring amendment ``when there are indicia 
of problems'' is too vague and leaves problems unaddressed which may 
result in a discharge as described in Sec. 112.1(b). A standard 
requiring an amendment only when the change would cause the spill 
potential to exceed the Plan's capabilities (because day-to-day changes 
do not affect the worst case spill) would have the effect of leaving no 
documentation of amendments which might affect discharges which do not 
reach the standard of ``worst case spill.'' While we encourage 
facilities to incorporate new procedures into Plans which would help to 
prevent discharges, amendments are still necessary when material 
changes are made to document those new procedures, and thus facilitate 
the enforcement of the rule's requirements. We disagree that a small 
facility should be exempt from making amendments for material changes. 
Amendments may be necessary at large or small facilities alike to 
prevent discharges after material changes.
    Material changes. A material change is one that may either increase 
or decrease the potential for a discharge. We agree with the commenter 
that the rule should be worded to indicate that the examples are for 
illustration only, because the items in the list may not always trigger 
amendments, and because the list is not exclusive. Only changes which 
materially affect operations trigger the amendment requirement. 
Ordinary maintenance or non-material changes which do not affect the 
potential for the discharge of oil do not.
    We disagree that decommissioning of a container that results in 
permanent closure of that container is not a material amendment. 
Decommissioning a container could materially decrease the potential for 
a discharge and require Plan amendment, unless such decommissioning 
brings the facility below the regulatory threshold, making the 
preparation and implementation of a Plan no longer a requirement. We 
also believe that the oversight of a Professional Engineer is necessary 
to ensure that the container is in fact properly closed.
    We agree that replacement of tanks, containers, or equipment may 
not be a material change if the replacements are identical in quality, 
capacity, and number. However, a replacement of one tank with more than 
one identical tank resulting in greater storage capacity is a material 
change because the storage capacity of the facility, and its consequent 
discharge potential, have increased.
    Changes of product. We have added to the list of examples, on a 
commenter's suggestion, ``changes of product.'' We added ``changes of 
product'' because such change may materially affect facility operations 
and therefore be a material change. An example of a change of product 
that would be a material change would be a change from storage of 
asphalt to storage of gasoline. Storage of gasoline instead of asphalt 
presents an increased fire and explosion hazard. A switch from storage 
of gasoline to storage of asphalt might result in increased stress on 
the container leading to its failure. Changes of product involving 
different grades of gasoline might not be a material change and thus 
not require amendment of the Plan if the differing grades of gasoline 
do not substantially change the conditions of storage and potential for 
discharge.
    A change in service may also be a material change if it affects the 
potential for a discharge. A ``change in service'' is a change from 
previous operating conditions involving different properties of the 
stored product such as specific gravity or corrosivity and/or different 
service conditions of temperature and/or pressure. Therefore, we have 
amended the rule to add ``or service'' after the phrase ``changes of 
product.''
    Documenting no change or certain activities. We agree that a log 
book may be used to document non-material, routine activities. However, 
this is not an appropriate substitute for amendment when you make 
material changes at the facility.
    EPA approval. We agree with the commenter's suggestion that EPA 
approval of an amendment is not required. However, if the RA is not 
satisfied that your amendment satisfies the requirements of these 
rules, he may require further amendment of your Plan.
    Time line for amendment implementation. We agree with commenters 
that we should not require Plan amendment before material changes are 
made. Therefore, we have revised the proposed rule to provide a maximum 
of six months for Plan amendment, and a maximum of six more months for 
amendment implementation. This is the current standard. We note that 
Sec. 112.3(f) allows the RA to authorize an extension of time to 
prepare and implement an amendment under certain circumstances.
    Editorial changes and clarifications. The phrase in the first 
sentence which read, ``potential to discharge oil as described in 
Sec. 112.1(b) of this part,'' becomes ``potential for a discharge as 
described in Sec. 112.1(b). ``Tanks'' becomes ``containers.'' 
``Commission or decommission'' becomes ``commissioning or 
decommissioning.''

Section 112.5(b)--Periodic Review of Plans

    Background. In 1991, we reproposed the current rule, which requires 
that the owner or operator review the Plan at least every three years, 
and amend it if more effective control and prevention technology would 
significantly reduce the likelihood of a spill, and if the technology 
had been field-proven at the time of the review.
    In 1997, we withdrew the 1991 proposal, and instead proposed a 
five-year review time frame, with the same technological conditions. In 
1997, we also proposed that the owner or operator certify that he had 
performed the review.
    Comments. Five-year review. Most commenters favored the change from 
three-to five-year review. Some

[[Page 47092]]

commenters noted that a five-year review period would make it easier to 
coordinate reviews of related plans, such as facility response plans 
required by part 112. A few opposed it, preferring the current three-
year review period. They believed that five-year review might lead to 
reduced maintenance and consequent environmental harm, especially in 
the absence of any requirements for a facility to ensure that personnel 
are familiar with planning goals and proposed response actions, 
including personnel who are rotated. One commenter suggested that the 
longevity of a tank warranty should be the determining factor in the 
length of review time. Another suggested that there should be no 
particular time period prescribed because the requirement for an 
amendment whenever a material change is made is sufficient.
    Completion of review. Commenters split almost evenly on the 
proposed requirement for certification of completion of the review. 
Opponents of the certification proposal believed generally that it is 
unnecessary paperwork that will not benefit the environment. One 
commenter suggested that instead of documenting completion of review, a 
facility might instead date the Plan to show review and date each 
amendment. One commenter thought that the certifications should have to 
be forwarded to the Regional Administrator. Others asked whether the 
certification could be documented in a log book, instead of in the 
Plan. Another commenter asked at what management level certification 
should be required. One commenter believed that Plans amended due to 
five-year reviews should not require owner or operator certification 
because any amendments to the Plan have to be reviewed and certified by 
a PE. Another commenter noted that no specific language was provided 
for the certification. One commenter urged that the PE should be 
allowed to document that no change is necessary after reviewing planned 
changes, or that further study is required, or that an amendment is 
necessary.
    Response to comments. Five-year review. We agree that a five-year 
review period will make coordination of review of related plans, such 
as facility response plans required by part 112, easier. We disagree 
that a five-year review period will lead to reduced maintenance or 
increased environmental harm. Amendment of a Plan will still be 
necessary when a material change is made affecting the facility's 
potential to discharge oil, perhaps after certain discharges as 
required by the RA under Sec. 112.4(a), and perhaps after on-site 
review of a Plan (see Sec. 112.4(d)). Plus the Plan must be implemented 
at all times. These opportunities ensure that Plans will be current. We 
also disagree that the length of the tank warranty should be the 
determining factor for a technological review. Technology changes 
enough within a five-year period to warrant required review within such 
time period whether or not other changes occur. Amendments other than 
the five-year review amendments may not be based on the need to learn 
of improved technology. Those amendments might result from deficiencies 
in the Plan, on the need to make repairs, or to remedy the cause of a 
discharge.
    Calculation of time between reviews. The change in the rule from 
three-year to five-year reviews requires some explanation as to when a 
review must be conducted. For example, a facility became subject to the 
rule on January 1, 1990. The first three-year review should have been 
conducted by January 1, 1993, the second by January 1, 1996, and the 
third by January 1, 1999. The next review must be conducted by January 
1, 2004, due to the rule change. In other words, an existing facility 
must complete the review within 5 years of the date the last review 
must have been completed. A facility becoming operable on or after the 
effective date of the rule will begin a five-year cycle at the date it 
becomes subject to part 112.
    Completion of review. We disagree that documentation of completion 
of review has no environmental benefit. Its benefit lies in the fact 
that it shows that someone reviewed the Plan to determine if better 
technology would benefit the facility and the Plan is current. 
Documentation of completion of review is necessary whether or not any 
amendments are necessary in order to clearly show that the review was 
done. Mere dating of the Plan or of an amendment does not show that you 
performed the required review. Documentation of completion of review is 
a function of the owner or operator, whereas certification of any 
resulting technical amendment is a function of the PE. We disagree that 
documentation of completion should be forwarded to the Regional 
Administrator because it would increase the information collection 
burden without an environmental benefit. It is sufficient that the 
review be done. When the Regional Administrator wishes to verify 
completion of review, he may do so during an on-site inspection.
    How to document completion of review. You must add documentation of 
completion of review either at the beginning or the end of the Plan, or 
maintain such documentation in a log book appended to the Plan or other 
appendix to the Plan. You may document completion in one of two ways. 
If amendment of the Plan is necessary, then you must state as much, and 
that review is complete. This statement is necessary because Plan 
amendments may result either from five-year review or from material 
changes at the facility affecting its potential for discharge, or from 
on-site review of the Plan. There is no way to know which circumstance 
causes the amendment without some explanation. If no amendments are 
necessary, you must document completion of review by merely signing a 
statement that you have completed the review and no amendments are 
necessary. You may use the words suggested in the rule to document 
completion, or make any similar statement to the same effect.
    Who documents review. The owner or operator of the facility, or a 
person at a management level with sufficient authority to commit the 
necessary resources, must document completion of review.
    Time line for amendment implementation. We agree with commenters 
(see comments on proposed Sec. 112.5(a)) that the preparation and 
implementation of Plan amendments require more time than proposed. The 
same rationale applies to the preparation and implementation of 
amendments required due to five-year reviews. Therefore, we will 
require adherence to the time lines laid down in Sec. 112.5(b) for 
amendments. Currently, Sec. 112.5(b) requires that Plan amendments be 
prepared within six months. It is silent as to time lines for 
implementation. Therefore, we have revised the rule to clarify that 
amendments must be implemented as soon as possible, but within the next 
six months. This is the current standard for implementation of certain 
other amendments. See, for example, Secs. 112.3(a) and 112.4(e). We 
note that Sec. 112.3(f) allows you to request an extension of time to 
prepare and implement an amendment.
    Editorial changes and clarifications. We have changed the word 
``certification'' to a requirement to document completion of the review 
to avoid the legal effect a certification may have. The intent of the 
certification proposal was merely to show that an owner or operator 
performed a review of the Plan every five years. 62 FR 63814, December 
2, 1997. A false documentation of completion of review of the Plan is a 
deficiency in the Plan and may be cited as a violation of these

[[Page 47093]]

rules. ``Spill event,'' in the second sentence, becomes ``discharge as 
described in Sec. 112.1(b).

Section 112.5(c)--PE Certification of Technical Amendments

    Background. In 1991, we proposed that all amendments to the Plan 
must be certified by a PE with the exception of changes to the contact 
list. The current rule requires certification of all amendments.
    Comments. A few commenters suggested that the value of PE 
certification for amendments does not justify the cost. Another 
commenter questioned when recertification of the entire Plan was 
required, rather than just the amendment in question. Several 
commenters suggested that the recertification requirement be limited to 
those changes that materially affect the facility's potential to 
discharge oil.
    Response to comments. It is the responsibility of the owner or 
operator to document completion of review, but completion of review and 
Plan amendment are two different processes. PE certification is not 
necessary unless the Plan is amended.
    We believe that PE certification is necessary for any technical 
amendment that requires the application of good engineering practice. 
We believe that the value of such certification justifies the cost, in 
that good engineering practice is essential to help prevent discharges. 
Therefore, we have amended the rule to require PE certification for 
technical changes only. Non-technical changes not requiring the 
exercise of good engineering practice do not require PE certification. 
Such non-technical changes include but are not limited to such items 
as: changes to the contact list; more stringent requirements for 
stormwater discharges to comply with NPDES rules; phone numbers; 
product changes if the new product is compatible with conditions in the 
existing tank and secondary containment; and, any other changes which 
do not materially affect the facility's potential to discharge oil. If 
the owner or operator is not sure whether the change is technical or 
non-technical, he should have it certified.

Former Section 112.7(a)(1)--Certain pre-1974 Discharges

    Background. In 1991, we proposed to delete Sec. 112.7(a), which 
required a description of certain discharges to navigable waters or 
adjoining shorelines which occurred prior to the effective date of the 
rule in 1974, because that information was no longer relevant. 56 FR 
54620. We received several comments supporting the proposed deletion of 
this provision, and have deleted it.

Section 112.7 Introduction and (a)(1)--General Eequirements

    Background. In 1991, we reproposed the introduction to Sec. 112.7 
to clarify that the rule requires mandatory action, and that it is not 
just a guideline. In 1997, we reproposed a definition of SPCC Plan that 
included some substantive requirements. As noted above (see the ``SPCC 
Plan'' definition in Sec. 112.2), those substantive requirements have 
been transferred from the definition of ``SPCC Plan'' in Sec. 112.2 to 
this section.
    Section 112.7(a)(1) requires a discussion of the facility's 
conformance with the listed requirements in the rule.
    Comments. For a discussion of the ``should to shall to must'' 
comments and response to those comments, see the discussion above under 
that topic in section IV.C of this preamble.
    Cross-referencing. Several commenters criticized the requirement 
for sequential cross-referencing set forth in the 1997 proposed 
definition of ``SPCC Plan,'' alleging that it is confusing and provides 
no benefit. Another commenter asked how detailed the cross-referencing 
must be.
    Written Plans. Another commenter proposed that a ``written'' Plan 
might also include texts, graphs, charts, maps, photos, and tables, on 
whatever media, including floppy disk, CD, hard drive, and tape storage 
that allows the document to be easily accessed, comprehended, 
distributed, viewed, updated, and printed.
    Response to comments. Cross-referencing. We agree that the term 
``sequential'' cross-referencing may be confusing, and have therefore 
deleted it in favor of a requirement to provide cross-referencing. We 
disagree that cross-referencing provides no benefit. With the wide 
variation now allowed in differing formats, we need cross-referencing 
so that an inspector can tell whether the Plan meets Federal 
requirements, and whether it is complete. In addition, in order for an 
owner or operator to do his own check to ensure that his facility meets 
all SPCC requirements, he must go through the exercise of comparing his 
Plan to each SPCC requirement. Cross-referencing in the context of the 
rule means indicating the relationship of a requirement in the new 
format to an SPCC requirement. The cross-referencing must identify the 
Federal section and paragraph for each section of the new format it 
fulfills, for example, Sec. 112.8(c)(3). Note the cross-referencing 
table we have provided for your convenience in section II.A of this 
preamble.
    Written Plans. We agree that a ``written'' Plan might also include 
texts, graphs, charts, maps, photos, and tables, on whatever media, 
including floppy disk, CD, hard drive, and tape storage, that allows 
the document to be easily accessed, comprehended, distributed, viewed, 
updated, and printed. Whatever medium you use, however, must be readily 
accessible to response personnel in an emergency. If it is produced in 
a medium that is not readily accessible in an emergency, it must be 
also available in a medium that is. For example, a Plan might be 
electronically produced, but computers fail and may not be operable in 
an emergency. For an electronic Plan or Plan produced in some other 
medium, therefore, a backup copy must be readily available on paper. At 
least one version of the Plan should be written in English so that it 
will be readily understood by an EPA inspector.
    Editorial changes and clarifications. We have transferred all of 
the proposed substantive requirements in the 1997 proposed definition 
of ``SPCC Plan'' to the introduction of this section. We did this 
because we agree with commenters (see the comments on the definition of 
``SPCC Plan'' in Sec. 112.2) that definitions should not contain 
substantive requirements.
    We have revised the introduction to Sec. 112.7 to facilitate use of 
the active voice and to clearly note that the owner or operator, except 
as specifically noted, is responsible for implementing the rule.
    We also deleted language requiring a ``carefully thought-out'' SPCC 
Plan. Such language is unnecessary because the Plan must be prepared in 
accordance with good engineering practices. Another editorial revision 
in the introduction is the change from ``level with authority'' in the 
last sentence of proposed Sec. 112.7(a) to ``level of authority.'' A 
third revision is a change from ``format'' to ``sequence.'' We have 
transferred the part of the sentence proposed in 1991 dealing with the 
sequence of the Plan in Sec. 112.7(a)(1) to the introduction of 
Sec. 112.7.
    For consistency with response plan language in Sec. 112.20(h), the 
language in the introduction referring to alternative SPCC formats has 
been revised to read ``equivalent Plan acceptable to the Regional 
Administrator.'' The response plan language in Sec. 112.20(h) on 
``equivalent response plans'' has also been revised to include the 
``acceptable to the Regional Administrator'' language included in the 
introduction to Sec. 112.7. For a discussion of possible SPCC formats, 
see the discussion under the definition of ``SPCC Plan,'' above.

[[Page 47094]]

    We deleted the term ``sequentially cross-referenced'' because we 
agree that it may be misunderstood, and instead use the term ``cross-
referencing'' in the revised rule. As noted above, cross-referencing 
means identifying the requirement in the new format to the section and 
paragraph of the SPCC requirement. We have also substituted the word 
``part'' for ``section'' where ``cross-referencing'' and meeting 
``equivalent requirements'' are mentioned. We make this change because 
the rule requires compliance with any applicable provision in the part, 
not merely Sec. 112.7. We also clarify that the discussion of your 
facility's conformance with the requirements listed (see 
Sec. 112.7(a)(1)) means the requirements listed in part 112, not merely 
the requirements listed in Sec. 112.7.
    We also note that if the Plan calls for additional facilities or 
procedures, methods, or equipment not yet fully operational, you must 
discuss these items in separate paragraphs, and must explain separately 
the details of installation and operational start-up. The discussion 
must include a schedule for the installation and start-up of these 
items.

Section 112.7(a)(2)--Deviations from Plan Requirements

    Background. In 1991, we proposed to allow deviations from the 
requirements listed in Sec. 112.7(c) and in Secs. 112.8, 112.9, 112.10, 
and 112.11, as long as the owner or operator explained the reason for 
nonconformance and provided equivalent environmental protection by 
another means. The proposal was intended to implement the requirement 
for ``good engineering practice'' which is a cornerstone of the rule, 
and to provide flexibility in meeting the rule's requirements. We 
clearly noted in the rule that the Regional Administrator would have 
the authority to overrule any deviation.
    In 1993, we reproposed the section, eliminating language referring 
to the Regional Administrator's (RA's) authority to overrule 
deviations. Instead, we proposed that whenever you proposed a 
deviation, you would have to submit the entire Plan to the RA with a 
letter explaining how your Plan contained equivalent environmental 
protection measures in lieu of those explicitly required in the rule. 
The RA would have authority under the 1993 proposal to require 
amendment of the Plan if he determined that the measures described in 
the deviation did not provide equivalent protection.
    Comments. Some commenters supported the 1991 proposal. But others 
had concerns.
    Applicability--1991. Some commenters suggested that the Agency 
should add language to the rule making clear that a facility may 
deviate from the express requirements of the rule and may substitute 
alternatives based on good engineering practice. The commenters added 
that we should make clear that the equivalency provision in 
Sec. 112.7(a)(2) does not require mathematical equivalency of every 
requirement, but merely the achievement of substantially the same level 
of overall protection from the risk of discharge at the facility as the 
specific requirement seeks to achieve. Another commenter was concerned 
that proving the equivalence of measures to the satisfaction of 
Regional officials may be difficult. One commenter urged us to 
expressly state that PEs may substitute alternatives based on good 
engineering practice.
    RA oversight--1991. One commenter opposed the provision allowing 
the RA to overrule waivers/equivalent measures. As noted above, we 
withdrew the proposal to allow the RA to explicitly overrule waivers. 
Instead we substituted a proposed procedure whereby the RA could 
require you to amend your Plan. One commenter feared that PEs would be 
reluctant to certify alternate technologies due to the threat of 
potential liability.
    Deviation submission. One commenter opposed the proposed 
requirement to submit a Plan deviation and urged its deletion to make 
it consistent with the rest of the SPCC rule. The commenter argued that 
the deviation and Plan have already been certified by a PE, and there 
is no reason for EPA to be asked to second guess that certification in 
every case. The commenter also asserted that it is unduly burdensome to 
require regulated facilities to prepare a justification and submit a 
Plan to EPA for every waiver of the technical requirements. Another 
commenter questioned why the entire Plan should be submitted to the RA 
for review. The commenter suggested that only the portion or portions 
of the Plan that do not conform to the standard requirements should be 
submitted, adding that this step would help EPA to minimize the 
resources needed to review such waivers. One commenter suggested that 
the choice of preventive systems in the design and implementation of 
spill prevention measures should be left to the facility owner or 
operator. The commenter opposed giving the RA authority to require 
equivalent protection because he questioned how the RA will determine 
if the deviation will cause harm to the environment, and therefore lack 
equivalency. If such a provision is included, the commenter asked for 
an appeals process similar to the one suggested in Sec. 112.20(c).
    RA oversight--1993. One commenter favored the 1993 proposal. 
Opposing commenters believed that submission of deviations to the RA is 
unnecessary because PE certification ensures the application of good 
engineering practice.
    Secondary containment. Several commenters suggested that we 
explicitly say that equivalent protection should be defined to allow a 
compacted earthen floor and compacted earthen dike to provide secondary 
containment. The rationale for the comment was that other methods of 
secondary containment may be prohibitively expensive and unnecessary to 
protect against spills in primarily rural areas. One commenter 
suggested that we should clarify that the language of Sec. 112.7(c) 
applies only to oil storage areas.
    Response to comments. Applicability. We generally agree with the 
commenter that an owner or operator should have flexibility to 
substitute alternate measures providing equivalent environmental 
protection in place of express requirements. Therefore, we have 
expanded the proposal to allow deviations from the requirements in 
Sec. 112.7(g), (h)(2) and (3), or (i), as well as subparts B, and C, 
except for the listed secondary containment provisions in Sec. 112.7 
and subparts B and C. The proposed rule already included possible 
deviations for any of the requirements listed in Secs. 112.7(c), 112.8, 
112.9, 112.10, and 112.11. We have expanded this possibility of 
deviation to include the new subparts we have added for various classes 
of oils. We take this step because we believe that the application of 
good engineering practice requires the flexibility to use alternative 
measures when such measures offer equivalent environmental protection. 
This provision may be especially important in differentiating between 
requirements for facilities storing, processing, or otherwise using 
various types of oil.
    A deviation may be used whenever an owner or operator can explain 
his reasons for nonconformance, and provide equivalent environmental 
protection. Possible rationales for a deviation include when the owner 
or operator can show that the particular requirement is inappropriate 
for the facility because of good engineering practice considerations or 
other reasons, and that he can achieve equivalent

[[Page 47095]]

environmental protection in an alternate manner. For example, a 
requirement that may be essential for a facility storing gasoline may 
be inappropriate for a facility storing asphalt; or, the owner or 
operator may be able to implement equivalent environmental protection 
through an alternate technology. An owner or operator may consider cost 
as one of the factors in deciding whether to deviate from a particular 
requirement, but the alternate provided must achieve environmental 
protection equivalent to the required measure. The owner or operator 
must ensure that the design of any alternate device used as a deviation 
is adequate for the facility, and that the alternate device is 
adequately maintained. In all cases, the owner or operator must explain 
in the Plan his reason for nonconformance. We wish to be clear that we 
do not intend this deviation provision to be used as a means to avoid 
compliance with the rule or simply as an excuse for not meeting 
requirements the owner or operator believes are too costly. The 
alternate measure chosen must represent good engineering practice and 
must achieve environmental protection equivalent to the rule 
requirement. Technical deviations, like other substantive technical 
portions of the Plan requiring the application of engineering judgment, 
are subject to PE certification.
    In the preamble to the 1991 proposal (at 56 FR 54614), we noted 
that ``* * * aboveground storage tanks without secondary containment 
pose a particularly significant threat to the environment. The Phase 
One modifications would retain the current requirement for facility 
owners or operators who are unable to provide certain structures or 
equipment for oil spill prevention, including secondary containment, to 
prepare facility-specific oil spill contingency plans in lieu of the 
prevention systems.'' In keeping with this position, we have deleted 
the proposed deviation in Sec. 112.7(a)(2) for the secondary 
containment requirements in Secs. 112.7(c) and (h)(1); and for proposed 
Secs. 112.8(c)(2), 112.8(c)(11), 112.9(c)(2), 112.10(c); as well as for 
the new sections which are the counterparts of the proposed sections, 
i.e., Secs. 112.12(c)(2), 112.12(c)(11), 112.13(c)(2), and 112.14(c), 
because a more appropriate deviation provision already exists in 
Sec. 112.7(d). Section Sec. 112.7(d) contains the measures which a 
facility owner or operator must undertake when the secondary 
containment required by Sec. 112.7(c) or (h)(1), or the secondary 
containment provisions in the rule found at Secs. 112.8(c)(2), 
112.8(c)(11), 112.9(c)(2), 112.10(c), 112.12(c)(2), 112.12(c)(11), 
112.13(c)(2), and 112.14(c), are not practicable. Those measures are 
expressly tailored to address the lack of secondary containment at a 
facility. They include requirements to: explain why secondary 
containment is not practicable; conduct periodic integrity testing of 
bulk storage containers; conduct periodic integrity and leak testing of 
valves and piping; provide in the Plan a contingency plan following the 
provisions of 40 CFR part 109; and, provide a written commitment of 
manpower, equipment, and materials to expeditiously control and remove 
any quantity of oil discharged that may be harmful. Therefore, when an 
owner or operator seeks to deviate from secondary containment 
requirements, Sec. 112.7(d) will be the applicable ``deviation'' 
provision, not Sec. 112.7(a)(2).
    Deviation submission. We agree with the commenter that submission 
of a deviation to the Regional Administrator is not necessary and have 
deleted the proposed requirement. We take this step because we believe 
that the requirement for good engineering practice and current 
inspection and reporting procedures (for example, Sec. 112.4(a)), 
followed by the possibility of required amendments, are adequate to 
review Plans and to detect the flaws in them. Upon submission of 
required information, or upon on-site review of a Plan, if the RA 
decides that any portion of a Plan is inadequate, he may require an 
amendment. See Sec. 112.4(d). If you disagree with his determination 
regarding an amendment, you may appeal. See Sec. 112.4(e).
    RA oversight. Once an RA becomes aware of a facility's SPCC Plan as 
a result of an on-site inspection or the submission of required 
information, he is to follow the principles of good engineering 
practice and not overrule a deviation unless it is clear that such 
deviation fails to afford equivalent environmental protection. This 
does not mean that the deviation must achieve ``mathematical 
equivalency,'' as one commenter pointed out. But it does mean 
equivalent protection of the environment. We encourage innovative 
techniques, but such techniques must also protect the environment. We 
also believe that in general PEs will seek to protect themselves from 
liability by only certifying measures that do provide equivalent 
environmental protection. But the RA must still retain the authority to 
require amendments for deviations, as he can with other parts of the 
Plan certified by a PE.
    Not covered under the deviation rule. Deviations under 
Sec. 112.7(a)(2) are not allowed for the general and specific secondary 
containment provisions listed above because Sec. 112.7(d) contains the 
necessary requirements when you find that secondary containment is not 
practicable. We have amended both this paragraph and Sec. 112.7(d) to 
clarify this. Instead, the contingency planning and other requirements 
in Sec. 112.7(d) apply. Deviations are also not available for the 
general recordkeeping and training provisions in Sec. 112.7, as these 
requirements are meant to apply to all facilities, or for the 
provisions of Sec. 112.7(f) and (j). We already provide flexibility in 
the manner of recordkeeping by allowing the use of ordinary and 
customary business records. Training and a discussion of compliance 
with more stringent State rules are essential for all facilities. 
Therefore, we do not allow deviations for these measures.
    Secondary containment. Regarding the secondary containment 
requirements, the requirement in Sec. 112.7(c) applies not only to oil 
storage areas, but also to operational areas of the facility where a 
discharge may occur. Section 112.7(c) may apply to any area of the 
facility where a discharge is possible. Other secondary containment 
provisions in this part have more particular applicability, e.g., 
Secs. 112.7(h)(1), 112.8(c)(2), 112.8(c)(11), 112.9(c)(2),112.10(c), 
and their counterparts in subpart C. We decline to specify that a 
compacted earthen floor and compacted earthen dike will always satisfy 
the secondary containment requirements. Those methods may, however, be 
acceptable if there is no potential for oil to migrate through the 
compacted earthen floor or dike through groundwater to cause a 
discharge as described in Sec. 112.1(b).
    Editorial changes and clarifications. ``Equivalent protection'' 
becomes ``equivalent environmental protection'' throughout the 
paragraph.

Section 112.7(a)(3)--Facility Characteristics That Must be Described in 
the Plan

    Background. In 1991, we proposed a new section that would require 
you to describe the essential characteristics of your facility in the 
Plan. Those characteristics are discussed below. In the description, 
you would also be required to provide a facility diagram that included 
the location and contents of all tanks, regardless of whether the tanks 
are subject to all the provisions of 40 CFR part 280 or a State program 
approved under 40 CFR part 281, or otherwise subject to part 112. The 
rationale for the diagram was that it would assist in response actions.

[[Page 47096]]

Responders would have a means to know where all containers are, to help 
ensure their safety in conducting a response action and aid in the 
protection of life and property.
    Comments. General description of characteristics. Two commenters 
asked that the requirements proposed for Plan characteristics be listed 
on a facility basis rather than a tank basis because otherwise the 
proposal would be too resource intensive. The commenters did not 
provide cost estimates.
    Facility diagram. Two commenters supported the proposal. Opposing 
commenters asserted that the diagram would be too costly and add little 
to the Plan. One commenter said that the requirement was redundant 
because many States require the same thing. Two commenters opposed 
marking the contents of the tanks because those contents may change 
frequently, requiring Plan amendment each time. One commenter suggested 
that instead the facility maintain a separate list of tank contents 
when changes occur frequently over a short span of time to eliminate 
the need to constantly amend the diagram. Other commenters requested a 
de minimis exemption for small containers for the diagram, suggesting 
levels of 660 gallons or less. Some of these commenters suggested that 
the diagram be discretionary for storage volumes of less than 10-15,000 
gallons. Other commenters asked whether exempt materials would have to 
be marked as to content, for example, products which are not oil. Some 
believed that the inclusion of otherwise exempt containers in the 
diagram was unreasonable. One commenter suggested the diagram should 
include transfer stations and connecting pipes. Another commenter asked 
for clarification that underground tanks, whether subject to SPCC or 
not, need to be included in the diagram.
    Unit-by-unit storage capacity. Several commenters asked for 
clarification of the meaning of the term ``unit-by-unit storage 
capacity.'' Many commenters asked for specification of a minimum size, 
and some suggested sizes, ranging from 660 gallons to 10,000 gallons.
    Type and quantity of oil stored. We received one comment on this 
item. The commenter opposed the information requirement because ``the 
way a tank is used changes often and the adequacy of response to an 
accidental discharge does not depend on the type of oil stored.''
    Estimates of quantity of oils potentially discharged. The few 
comments we received opposed this information requirement. One 
commenter argued that the item requests a ``prediction'' of future 
events. Another asserted that it would not be possible to give 
estimates of oil potentially discharged from flowlines or gathering 
systems. One commenter argued that mobile facilities should be exempt 
from this requirement because the exact site information changes with 
the movement of equipment.
    Possible spill pathways. Two commenters wrote that the proposed 
requirement ``could be an infinite number and serves no useful 
purpose.'' One commenter asked that the requirement be replaced by a 
requirement to describe the most likely spill pathways to navigable 
water.
    Spill prevention measures (including loading areas and transfers). 
One commenter suggested that the beginning of the paragraph be revised 
to read, ``Secondary containment'' instead of ``Spill prevention 
measures. . . .'' See also the discussion on loading areas under 
Sec. 112.7(h).
    Spill controls and secondary containment. One commenter thought 
that this paragraph should refer to ``other drainage control features 
and the equipment they protect.''
    Spill countermeasures. One commenter suggested that this paragraph 
be revised to read, ``Prevention, control, or countermeasure features, 
other than secondary containment and drainage control, and the 
equipment which they protect.'' Another commenter argued that mobile 
drilling and workover rigs either on or off shore should be exempt from 
this requirement because supplying site specific spill and clean-up 
information for a mobile source that will move from one site to another 
is not feasible. One commenter suggested that the contingency planning 
requirements in this paragraph, as well as in Sec. 112.7(b) and (d)(1), 
seem unnecessarily complex because the same basic information seems to 
be required in several different places in the proposed regulation. The 
commenter went on to suggest that EPA consolidate these requirements. 
Another commenter suggested that this paragraph should be deleted and 
removed to a response plan section which he suggested, because the 
information called for requires response information.
    Disposal of recovered materials. Two commenters supported the 
proposal in general, but one suggested that it is not feasible nor 
useful to discuss particular alternatives. One of the favorable 
commenters suggested that we should encourage recycling of spilled oil 
rather than mere disposal. Another commenter argued that mobile 
drilling and workover rigs either on or off shore should be exempt from 
this requirement because supplying site specific spill and clean-up 
information for a mobile source that will move from one site to another 
is not feasible.
    Some opposing commenters believed that the proposal would preclude 
bioremediation. Others believed that it was too costly. One commenter 
suggested that the ``costs associated with off-site disposal of oil-
saturated soil from a typical secondary containment facility after a 
contained spill event will cost an operator as much as $4,700, 
calculated at the cost of $90 per ton of removed soil for 
transportation and disposal fees and the associated leachate and waste 
analysis but excluding the internal costs associated with the actual 
excavation work.'' Other commenters believed that we have no authority 
to ask the question because the subject matter is regulated either by 
State law or another Federal program, such as the solid waste program. 
One commenter asked for an exemption for mobile facilities from this 
requirement.
    Contact list. Several commenters favored the proposal. One 
commenter suggested that the list name the cleanup contractor with whom 
the facility has a relationship, not merely the name of any cleanup 
contractor.
    One commenter favored the inclusion of local emergency planning 
contacts in the required information. Another opposed it as duplicative 
of information in the HAZWOPER Plan. A commenter requested an exemption 
for mobile facilities. Another commenter believed we lack authority to 
request the information. One commenter suggested that the list be 
restricted to Federal or State agencies that must be notified in case 
of the accidental discharge of oil. Another commenter argued that 
mobile drilling and workover rigs either on or off shore should be 
exempt from this requirement because supplying site specific spill and 
clean-up information for a mobile source that will move from one site 
to another is not feasible. One commenter suggested that this paragraph 
should be deleted and removed to a response plan section which he 
suggested, because the information called for requires response 
information.
    Downstream water suppliers. Several commenters suggested that the 
proposed requirement to include information on downstream water 
suppliers who must be contacted in case of a discharge to navigable 
waters should be limited to those ``who might reasonably be affected by 
a discharge.'' Others asked that the downstream distance be specified. 
They added that private wells should be excluded from the notice. 
Several

[[Page 47097]]

commenters asked how they might identify such suppliers. Yet others 
believed that such notification was the responsibility of local 
emergency response agencies.
    Response to comments. General description of characteristics. The 
following characteristics must be described on a per container basis: 
the storage capacity of the container, type of oil in each container, 
and secondary containment for each container. The other characteristics 
may be described on a facility basis. We disagree that these 
requirements are too resource intensive. The major new requirement in 
Sec. 112.7(a)(3) is the facility diagram. Based on site inspections and 
professional judgment, we estimate unit costs for compliance with this 
section to be $33 for a small facility, $39 for a medium facility, and 
$5 for a large facility. Large facilities are assumed to already have a 
diagram that may be attached to the SPCC Plan. The other items 
mentioned in Sec. 112.7(a)(3)--storage capacity of each container, 
prevention measures, discharge controls, countermeasures, disposal 
methods, and the contact list--are already required under the current 
rule or required by good engineering practice. As described in the 
Information Collection Request for this rule, the cost of Plan 
preparation includes these items, e.g., field investigations to 
understand the facility design and to predict flow paths and potential 
harm, regulatory review, and spill prevention and control practices.
    Providing information on a container-specific basis helps the 
facility to prioritize inspections and maintenance of containers based 
on characteristics such as age, capacity, or location. It also helps 
inspectors to prioritize inspections of higher-risk containers at a 
facility. Container-specific information helps an inspector verify the 
capacity calculation to determine whether a Plan is needed; and, helps 
to formulate contingency planning if such planning is necessary.
    Facility diagram. The facility diagram is important because it is 
used for effective prevention, planning, management (for example, 
inspections), and response considerations and we therefore believe that 
it must be part of the Plan. The diagram will help the facility and 
emergency response personnel to plan for emergencies. For example, the 
identification of the type of oil in each container may help such 
personnel determine the risks when conducting a response action. Some 
oils present a higher risk of fire and explosion than other less 
flammable oils.
    Inspectors and personnel new to the facility need to know the 
location of all containers subject to the rule. The facility diagram 
may also help first responders to determine the pathway of the flow of 
discharged oil. If responders know possible pathways, they may be able 
to take measures to control the flow of oil. Such control may avert 
damage to sensitive environmental areas; may protect drinking water 
sources; and may help responders to prevent discharges to other 
conduits leading to a treatment facility or navigable waters. Diagrams 
may assist Federal, State, or facility personnel to avoid certain 
hazards and to respond differently to others.
    The facility diagram is necessary for all facilities, large or 
small, because the rationale is the same for both. While some States 
may require a diagram, others do not. SPCC is a Federal program 
specifying minimum requirements, which the States may supplement with 
their own more stringent requirements. We note that State plans may be 
used as SPCC Plans if they meet all Federal requirements, thus avoiding 
any duplication of effort if the State facility diagram meets the 
requirements of the Federal one.
    Facility diagram--container contents. The facility diagram must 
include all fixed (i.e., not mobile or portable) containers which store 
55 gallons or more of oil and must include information marking the 
contents of those containers. If you store mobile containers in a 
certain area, you must mark that area on the diagram. You may mark the 
contents of each container either on the diagram of the facility, or on 
a separate sheet or log if those contents change on a frequent basis. 
Marking containers makes for more effective prevention, planning, 
management, and response. For example, a responder may take one type of 
emergency measure for one type of oil, and another measure for another 
type. As noted above, oils differ in their risk of fire and explosion. 
Gasoline is highly flammable and volatile. It presents the risk of fire 
and inhalation of vapors when discharged. On the other hand, motor oil 
is not highly flammable, and there is no inhalation of vapors hazard 
associated with its discharge.
    In an emergency, the responder may not have container content 
information unless it is clearly marked on a diagram, log, or sheet. 
For emergency response purposes, we also encourage, but do not require 
you to mark on the facility diagram containers that store CWA hazardous 
substances and to label the contents of those containers. When the 
contents of an oil container change, this may or may not be a material 
change. See the discussion on Sec. 112.5(a).
    Facility diagram--De minimis containers. We have established a de 
minimis container size of less than 55 gallons. You do not have to 
include containers less than 55 gallons on the facility diagram.
    Facility diagram--Transfer stations, connecting pipes, and USTs. We 
agree that all facility transfer stations and connecting pipes that 
handle oil must be included in the diagram, and have amended the rule 
to that effect. This inclusion will help facilitate response by 
informing responders of the location of this equipment. The location of 
all containers and connecting pipes that store oil (other than de 
minimis containers) must be marked, including USTs and other containers 
not subject to SPCC rules which are present at SPCC facilities. Again, 
this is necessary to facilitate response by informing responders of the 
location of these containers.
    Unit-by-unit storage capacity. For clarity, we have changed the 
term in Sec. 112.7(a)(3)(i), ``unit-by-unit'' storage capacity, to 
``type of oil in each container and its storage capacity.'' As noted 
earlier, this requirement applies only to containers of 55 gallons or 
greater.
    Type and quantity of oil stored. We have eliminated proposed 
Sec. 112.7(a)(3)(ii) because it repeats information requested in 
revised Sec. 112.7(a)(3)(i). We ask for information concerning storage 
capacity and type of oil stored in each container in that paragraph.
    Estimates of quantity of oils potentially discharged. We have 
eliminated proposed Sec. 112.7(a)(3)(iii) because it repeats 
information sought in Sec. 112.7(b) regarding ``a prediction of the 
direction, rate of flow, and total quantity of oil which could be 
discharged* * * .'' We will address the substantive comments under the 
discussion of that paragraph.
    Possible spill pathways. We have eliminated proposed 
Sec. 112.7(a)(3)(iv) because the proposal repeats information sought in 
Sec. 112.7(b) regarding ``a prediction of the direction, rate of flow, 
and total quantity of oil which could be discharged.* * *'' Again, we 
will address the substantive comments under the discussion of that 
paragraph.
    Spill prevention measures. We have revised this paragraph to read 
``discharge prevention measures.'' We disagree with the commenter that 
the paragraph should be labeled ``secondary containment.'' The term 
``discharge prevention measures'' is better because

[[Page 47098]]

it encompasses both secondary containment and other discharge 
prevention measures.
    Spill controls and secondary containment. We have revised this 
paragraph to refer to ``discharge'' controls. In response to a 
commenter, we have also included a reference to drainage controls in 
the paragraph because drainage systems or diversionary ponds might be 
an alternative means of secondary containment. See 
Sec. 112.7(c)(1)(iii) and (v).
    Spill countermeasures. We disagree that the paragraph should be 
revised to read, ``Prevention, control, or countermeasure features, 
other than secondary containment and drainage control, and the 
equipment which they protect,'' because we believe that the language we 
proposed, as revised, better captures the information we are seeking. 
Our revised language refers to discovery, response, and cleanup, which 
are features that are absent from the commenter's suggestion, and for 
which a discussion in the Plan is necessary in order to be prepared for 
any discharges.
    We disagree that either onshore or offshore mobile drilling and 
workover rigs should be exempted from this requirement because the 
information necessary to this requirement is not always site specific, 
and may be included in a general plan for a mobile facility.
    We also disagree that the information required in this paragraph is 
redundant of information required in Secs. 112.7(b) and 112.7(d)(1). 
Each of the sections mentioned requires discrete and different 
information. Section 112.7(a)(3)(iv) requires information concerning a 
facility's and a contractor's capabilities for discharge discovery, 
response, and cleanup. Section 112.7(b) requires information concerning 
the potential consequences of equipment failure. Section 112.7(d)(1) 
requires a contingency plan following the provisions of part 109, which 
includes coordination requirements with governmental oil spill response 
organizations.
    We disagree that the information should be placed in a response 
section, because most SPCC facilities are not required to have response 
plans, and the information is necessary to prepare for discharge 
discovery, response, and cleanup.
    Disposal of recovered materials. This provision applies to all 
facilities, including mobile facilities, because proper disposal of 
recovered materials helps prevent a discharge as described in 
Sec. 112.1(b) by ensuring that the materials are managed in an 
environmentally sound manner. Proper disposal also assists response 
efforts. If a facility lacks adequate resources to dispose of recovered 
oil and oil-contaminated material during a response, it limits how much 
and how quickly oil and oil-contaminated material is recovered, thereby 
increasing the risk and damage to the environment.
    We disagree that this paragraph would preclude bioremediation 
efforts, as some commenters suggested. Bioremediation may be a method 
of proper disposal. The paragraph merely requires that you discuss the 
methods employed to dispose of recovered materials; it does not require 
that materials recovered be ``disposed'' of in any particular manner 
nor is it an independent requirement to properly dispose of materials. 
Thus, there is no infringement on or duplication of any other State or 
Federal program or regulatory authority. Because it does nothing more 
than require that you explain the method of disposal of recovered 
materials, we also disagree that this provision is too costly. Also, we 
assume that good engineering practice will in many cases include a 
discussion of such disposal already. By describing those methods in the 
Plan, you help ensure that the facility has done the appropriate 
planning to be able to dispose of recovered materials, should a 
discharge occur. We support the recycling of spilled oil to the extent 
possible, rather than its disposal. For purposes of this rule, disposal 
of recovered materials includes recycling of those materials.
    We disagree that either onshore or offshore mobile drilling and 
workover rigs should be exempted from this requirement because the 
information necessary to this requirement is not always site specific, 
and may be included in a general plan for a mobile facility.
    Contact list. In response to a comment, we have amended the rule to 
require that the cleanup contractor listed must be the one with whom 
the facility has an agreement for response that ensures the 
availability of the necessary personnel and equipment within 
appropriate response times. An agreement to respond may include a 
contract or some less formal relationship with a cleanup contractor. No 
formal written agreement to respond is required by the SPCC rule, but 
if you do have one, you must discuss it in the Plan.
    We have ample authority to ask for information concerning emergency 
contacts under the CWA because it is relevant to the statute's 
prevention, preparedness, and response purposes. Furthermore, it is an 
appropriate question for all facilities, including mobile facilities, 
because it is necessary to prepare for discharges and to aid in prompt 
cleanup when they occur. Having a Plan which contains a contact list of 
response organizations is a procedure and method to contain a discharge 
of oil as specified in CWA section 311(j)(1)(C). However, we have 
eliminated references to specific State and local agencies in the event 
of discharges in favor of a reference to ``all appropriate State and 
local agencies.'' ``Appropriate'' means those State and local agencies 
that must be contacted due to Federal or State requirements, or 
pursuant to good engineering practice. You may not always be required 
to notify fire departments, local emergency planning committees 
(LEPCs), and State emergency response commissions (SERCs), nor as an 
engineering practice do they always need to receive direct notice from 
the facility in the event of a discharge as described in Sec. 112.1(b). 
At times they might, but they might also receive notice from other 
sources, such as the National Response Center. Other State and local 
agencies might also need notice from you.
    We have added the word ``Federal'' to the list of all appropriate 
contact agencies because there are times when you must notify EPA of 
certain discharges. See Sec. 112.4(a). There might also be requirements 
under Federal statutes other than the CWA, for notice in such 
emergencies.
    We disagree that either onshore or offshore mobile drilling and 
workover rigs should be exempted from this requirement because the 
information necessary to this requirement is not always site specific, 
and may be included in a general plan for a mobile facility.
    We disagree that the information should be placed in a response 
section, because most SPCC facilities are not required to have response 
plans, and the information is necessary to prepare for response to an 
emergency.
    Downstream water suppliers. We have deleted the reference to 
``downstream water suppliers'' (i.e., intakes for drinking and other 
waters) because facilities may have no way to identify such suppliers. 
We agree with commenters that identifying such suppliers is more a 
function of State and local emergency response agencies. We note, 
however, that facilities that must prepare response plans under 
Sec. 112.20 must discuss in those plans the vulnerability of water 
intakes (drinking, cooling, or other).

[[Page 47099]]

    Editorial changes and clarifications. In the introduction to 
paragraph (a)(3), ``physical plant'' becomes ``physical layout.'' 
``Tanks'' becomes ``containers.'' In proposed paragraph (a)(3)(vi), 
redesignated as paragraph (a)(3)(iii), ``spill controls'' becomes 
``discharge or drainage controls.'' In proposed paragraph (a)(3)(vii), 
redesignated as paragraph (a)(3)(iv), ``spill countermeasures for spill 
discovery'' becomes ``countermeasures for discharge discovery.'' In 
proposed paragraph (a)(3)(ix), redesignated as paragraph (a)(3)(vi), 
``discharge to navigable waters'' becomes ``discharge as described in 
Sec. 112.1(b).''

Section 112.7(a)(4)--Spill Reporting Information in the Plan

    Background. In 1991, we proposed that documentation in this 
paragraph be sufficient to enable a person reporting a spill to provide 
essential information to organizations on the contact list.
    Comments. Several commenters had editorial comments, suggesting the 
rule refer to ``information'' rather than ``documentation'' on the 
theory that documentation refers to a past event, whereas the rule 
contemplates a future event. One commenter suggested that the section 
be qualified to indicate that a form for collecting spill report 
information be included in the Plan, or for ``small size facilities'' 
in the HAZWOPER reporting matrix. Another commenter suggested that a 
properly prepared SPCC Plan would assist the person reporting the spill 
to provide the requested information. One commenter asserted the 
proposed rule was duplicative of State requirements. Several commenters 
suggested that not all of the information will be available or 
applicable for a person reporting a discharge. One commenter suggested 
that this paragraph should be deleted and removed to a response plan 
section which he suggested, because the information called for requires 
response information.
    Response to comments. Documentation. We agree with commenters that 
the word ``documentation'' is inappropriate because it refers to a past 
event. Accordingly, as suggested by commenters, we have revised the 
rule to provide for ``information and procedures'' that would assist 
the reporting of discharges as described in Sec. 112.1(b). 
``Information'' refers to the facts which you must report, and 
``procedures'' refers to the method of reporting those facts. Such 
procedures must address whom the person relating the information should 
call, in what order the caller should call potential responders and 
others, and any other instructions necessary to facilitate notification 
of a discharge as described in Sec. 112.1(b). If properly noted, the 
information and procedures in the Plan should enable a person reporting 
a discharge to accurately describe information concerning that 
occurrence to the proper persons in an emergency. Any information or 
procedure not applicable will not have to be used. Available 
information on a discharge must be reported. Applicable procedures must 
be followed. And of course, any information that is not available 
cannot be reported.
    State requirements. While it is possible that this information may 
be duplicative of State requirements, the duplication is eliminated to 
the extent that you use your State SPCC Plan for Federal SPCC purposes. 
Where there is no State requirement, there is no duplication.
    Response plan exemption. We disagree that this paragraph should be 
placed in a response section, because most SPCC facilities are not 
required to have response plans, and the information is necessary to 
prepare for response to an emergency. However, if your facility has 
prepared and submitted a response plan to us under Sec. 112.20, there 
is no need to document this information in your SPCC Plan, because it 
is already contained in the response plan. See Sec. 112.20(h)(1)(i)-
(viii). Therefore, we have amended the rule to exempt those facilities 
with response plans from the requirements of this paragraph.
    Editorial changes and clarifications. We changed ``address'' to 
``address or location'' because some facilities do not have an exact 
address. ``Spill'' and ``spilled'' becomes ``discharge as described in 
Sec. 112.1(b)'' or ``discharged'' as appropriate in the context, 
``discharge'' being a defined term. ``Spill'' or ``spilled'' are not 
defined terms. ``The affected medium'' becomes ``all affected media.''

Section 112.7(a)(5)--Emergency Procedures

    Background. In 1991, we proposed this paragraph to ensure that 
portions of the Plan describing procedures to be used in emergency 
circumstances are organized in a manner to make them readily usable in 
an emergency.
    Comments. One commenter suggested that this paragraph should be 
deleted and removed to a response plan section which he suggested, 
because the information called for requires response information.
    Response to comments. We disagree this paragraph should be deleted 
because most SPCC facilities are not required to have a response plan, 
and the procedures to be used when a discharge occurs are necessary to 
prepare for an emergency. Because this information would repeat 
information contained in a response plan submitted under Sec. 112.20, 
we have excluded from the requirements of this paragraph those 
facilities which have submitted response plans. See 
Sec. 112.20(h)(3)(i)-(ix).

Section 112.7(b)--Fault Analysis

    Background. In 1991, we proposed only editorial changes to this 
paragraph dealing with fault analysis. The proposal would require an 
analysis of the major types of failures possible in a facility, 
including a prediction of the direction, rate of flow, and total 
quantity of oil that could be discharged as a result of each such 
failure.
    Comments. Applicability. One commenter wrote that the language in 
the first sentence of the proposed rule is less clear than current 
regulations. The commenter asserted that the proposed revision, perhaps 
inadvertently, does not specify the sections to which the certain 
``situations'' apply. The commenter suggested that current language is 
clearer and specifically focuses limited resources on situations for 
which there is a reasonable potential for discharge. The commenter 
argued that limited resources should not be consumed in developing flow 
rate, direction and quantity predictions in the SPCC Plan for 
situations without a reasonable potential for discharge to navigable 
waters.
    Several commenters asserted that the fault analysis required by 
this paragraph is ``too involved for small operators.'' They suggested 
that only development of responses to obvious scenarios, such as tank 
rupture, should be required. Commenters from the utility industry 
suggested that electrical equipment facilities should be exempt from 
the requirements in this paragraph. One commenter believed that mobile 
facilities should be exempt from the requirements in the paragraph 
because the exact site information changes with the movement of 
equipment.
    Failure factors. One commenter suggested that the rule should also 
focus on small discharges, not just ``major'' discharges. Another 
commenter asked for clarification as to what is a ``major failure'' and 
to what degree of sophistication the pathway prediction must be made. 
Another commenter suggested that the rule should adequately describe 
how detailed the analysis of potential spill pathways

[[Page 47100]]

should be. Another suggested that it would be impossible to give 
estimates of oil potentially discharged from flowlines or gathering 
systems.
    Response to comments. Applicability. We agree with the commenter 
that current language is clearer and will retain it. We therefore 
modified the first sentence contained in the proposed rule. We agree 
that the Plan must only discuss potential failure situations that might 
result in a discharge from the facility, not any failure situation. The 
rule requires that when experience indicates a reasonable potential for 
failure of equipment, the Plan must contain certain information 
relevant to those failures. ``Experience'' includes the experience of 
the facility and the industry in general.
    We disagree that the requirement is too difficult for owners or 
operators of small or mobile facilities, or of flowlines or gathering 
lines, or of electrical equipment facilities, or other users of oil. We 
believe that a Professional Engineer may evaluate the potential risk of 
failure for the aforementioned facilities and equipment and predict 
with a certain degree of accuracy the result of a failure from each. We 
note that since we have raised the regulatory threshold, this 
requirement will not be applicable to many smaller facilities.
    Failure factors. To comply with this section, you need only address 
``major equipment'' failures. A major equipment failure is one which 
could cause a discharge as described in Sec. 112.1(b), not a minor 
failure possibility. To help clarify the type of equipment failures the 
rule contemplates, we have added examples of other types of failures 
that would trigger the requirements of this paragraph. Such other 
equipment failures include failures of loading/unloading equipment, or 
of any other equipment known to be a source of a discharge. The 
analysis required will depend on the experience of the facility and how 
sophisticated the facility equipment is. If your facility has simpler 
equipment, you will have less to detail. If you have more sophisticated 
equipment, you will have to conduct a more detailed analysis. If your 
facility's experience or industry experience in general indicates a 
higher risk of failure associated with the use of that equipment, your 
analysis will also have to be more detailed. This rationale and 
analytic detail are also applicable to electrical equipment facilities 
and other facilities that do not store oil, but contain it for 
operational use. Again, the required explanation will be tailored to 
the type of equipment used and the experience with that equipment.
    Spill pathways. The level of analysis concerning spill pathways 
will depend on the geographic characteristics of the facility's site 
and the possibility of a discharge as described in Sec. 112.1(b) that 
equipment failure might cause. However, the Professional Engineer 
should focus on the most obvious spill pathways.
    Because this information is facility specific, the owner or 
operator of a mobile facility will not be able to detail spill pathways 
in the general Plan for the facility each time the facility moves. 
However, the owner or operator must provide management practices in the 
general Plan that provide for containment of discharges in spill 
pathways in a variety of geographic conditions likely to be 
encountered. In case of a discharge at a particular facility, the owner 
or operator would then take appropriate action to contain or remove the 
discharge. For example, the Plan may provide that a rig must be 
positioned to minimize or prevent discharges as described in 
Sec. 112.1(b); or it may provide for the use of spill pans, drip trays, 
excavations, or trenching to augment discharge prevention.
    Editorial changes and clarifications. We made minor editorial 
changes in the proposal's second sentence that reflect a plain language 
format. We revised the phrase in the proposed second sentence of the 
paragraph from ``each major type of failure'' to ``each type of major 
equipment failure.''

Section 112.7(c)--Secondary Containment.

    Background. The SPCC Task force concluded that aboveground storage 
tanks without secondary containment could pose a particularly 
significant threat to the environment. We noted in the 1991 preamble 
that the proposed rule modifications would ``retain the current 
requirement for facility owners or operators who are unable to provide 
certain structures or equipment for oil spill prevention, including 
secondary containment, to prepare facility-specific contingency plans 
in lieu of prevention systems.'' 56 FR 54614.
    In 1991, we proposed to modify the current standard that dikes, 
berms, or retaining walls must be ``sufficiently impervious.'' We 
proposed that the current ``sufficiently impervious'' standard for 
secondary containment be replaced with a standard requiring that the 
entire containment system, including walls and floor, must be 
impervious to oil for 72 hours. The rationale was that a containment 
system that is impervious to oil for 72 hours would allow time for 
discovery and removal of an oil discharge in most cases.
    We also noted that for some facilities such as electrical 
substations, compliance with this section might not be practicable. We 
said that since their purpose was not the storage of oil in bulk, they 
did not need to comply with the secondary containment requirements 
designed for bulk storage tanks in Secs. 112.8(c) and 112.9(d), but 
only the secondary containment requirements in Sec. 112.7(c), and that 
the Sec. 112.7(c) requirement for secondary containment might be 
satisfied by various means including drainage systems, spill diversion 
ponds, etc. We added that the alternative requirements contained in 
proposed Sec. 112.7(d) would fulfill the intent of the CWA when a 
facility could not provide secondary containment due to the 
impracticability of installation. 56 FR 54621.
    Comments. Editorial changes and clarifications. Several commenters 
suggested that the reference to prevention of discharges to ``surface 
waters'' be changed to prevention of discharges to ``navigable 
waters.''
    Contingency planning. One commenter suggested revising the rules to 
allow the use of the contingency plan contemplated in Sec. 112.7(d) 
instead of secondary containment measures. Another commenter asserted 
that a contingency plan is not an acceptable substitute for secondary 
containment and advocated that all facilities be required to have 
secondary containment.
    Applicability of requirement. Numerous electric utility commenters 
suggested that secondary containment was impractical for their 
facilities because it might cause a safety hazard. Instead, they argued 
for the use of contingency planning. One commenter asserted that 
secondary containment at sites used for the maintenance and operation 
of the air traffic control system was also impracticable because those 
sites are often very small, isolated, unmanned, and visited only on a 
quarterly basis. Another commenter asked that wastewater treatment 
tanks be exempted from the secondary containment requirement because 
their use is not to store oil, but to treat water. Other containers not 
used for storage, but other purposes might include stormwater surge 
tanks, activated sludge aeration tanks, equalization basins, dissolved 
and inducted air floatation tanks, oil/water separators, sludge 
digesters, etc. Another commenter urged that all oil-filled equipment 
located in a 25-year floodplain be required to have secondary 
containment.

[[Page 47101]]

    One commenter asked that we clarify that the secondary containment 
requirement in this section does not apply to the following equipment 
at onshore production facilities: flowlines because of the prohibitive 
cost of construction for miles of lines; fired vessels because of the 
danger of pooling spilled oil around an ignition source; and, 
pressurized vessels because a leak from such vessel might be sprayed 
beyond the area that a reasonable dike might enclose. One commenter 
suggested that all in-use hydraulic equipment such as cranes, jacks, 
elevators, forklifts, etc., be exempted from the secondary containment 
requirement because it would be impractical to provide structures for 
such equipment. Others suggested that mobile facilities should be 
exempt from the secondary containment requirement because it would be 
infeasible to provide it. Similarly, one commenter suggested that the 
requirement was infeasible for production facilities due to their 
sometimes remote locations or difficult terrain and soil conditions. 
Yet another commenter wanted us to clarify that underground piping is 
not subject to the rule's secondary containment provisions.
    One commenter asserted that mining sites should be exempted from 
the secondary containment requirement because the containment 
requirements would be ``excessive'' for such sites and result in 
``little resultant net environmental benefit.'' A commenter 
representing various small facilities asked for exemption from the 
requirement on the basis that the risk is lower for those facilities.
    Methods of secondary containment. As to methods of secondary 
containment, several commenters urged that the existence of ``natural'' 
structures and/or drainage could meet this requirement. Other 
commenters suggested that vaulted tanks or double-walled tanks in 
themselves meet the secondary containment requirement. One commenter 
suggested that we remove sorbent materials or booms from the list of 
acceptable secondary containment structures because they are not a 
substitute for impervious dikes and impoundment floors.
    72-hour impermeability standard. We received numerous comments on 
the proposed 72-hour impermeability standard. Several commenters 
favored the standard. Many were opposed. Of the opponents, some favored 
the current standard that the dikes, berms or retaining walls be 
``sufficiently impervious'' to contain spilled oil. Other commenters 
thought that the proposed requirement to prevent escape of oil to 
surface waters should be replaced with a standard of preventing the 
escape of oil to ``the environment'' or to ``navigable waters.'' Others 
asked for clarification of the term ``impervious,'' asserting that it 
is a qualitative term that requires definition by engineering 
standards. One commenter requested that if an impervious containment 
system cannot be provided, that facilities be required to assure that 
conduits that may cause substantial migration of free products are 
appropriately monitored for discharges. Another commenter asked us to 
specify acceptable liner materials, in lieu of a total imperviousness 
requirement.
    Costs. One commenter suggested that our industry cost estimate for 
the proposed 1991 regulations--of $441 million in the first year and 
$71.8 million each subsequent year--was erroneously low, but did not 
provide his own cost estimates. The commenter came to this conclusion 
by calculating compliance cost estimates for the following 
requirements: 72-hour impermeability for secondary containment and 
diked areas, and installation of containment systems at all truck 
loading locations. The commenter estimated the cost of the effects of 
two proposed items for New York oil and gas producers, not all us 
producers, at in excess of $78 million; he estimated the cost of the 
proposed 72 hour oil impermeability requirement at $48 million, and if 
earthen dikes and diked areas cannot meet the secondary containment 
standards at truck loading areas, at least $30 million.
    Alternate impermeability standards. Commenters suggested a number 
of alternate impermeability standards. One commenter suggested a 
standard that the containment system be impervious to oil and water for 
72 hours. Another commenter suggested that the standard apply only in 
environmentally sensitive areas. Some suggested that the standard 
should be inapplicable at facilities that are staffed around the clock, 
seven days a week. One commenter suggested a phase-in of the 
requirement. Some thought that the impermeability standard should not 
apply to heavier oils, particularly number 5 and 6 oils.
    Alternate time frames. Others suggested differing time standards in 
lieu of 72 hours such as 24 hours at manned facilities, 36 hours or 
increased inspections, ``as soon as practicable,'' ``for the duration 
of the response,'' or no time limit at all. One commenter asked when 
the 72 hours begins to run, whether it begins at the time of the 
discovery of the discharge or the time of occurrence.
    Containment or impermeability. Other commenters asserted that the 
rule should address containment rather than impermeability because they 
assert that the point of a containment structure is ``to keep the 
discharge from reaching the waters of the United States.'' In the same 
vein, two commenters asked EPA to clarify that the leaching of small 
amounts of oil that does not reach the water table or surface waters 
meets the impermeability requirement, while a third asked that we 
clarify that we are concerned only with horizontal rather than vertical 
discharges of oil.
    Sufficient freeboard. See the comments to Sec. 112.8(c)(2) under 
this topic.
    Response to comments. Contingency planning. A contingency plan 
should not be used routinely as a substitute for secondary containment 
because we believe it is normally environmentally better to contain oil 
than to clean it up after it has been discharged. Secondary containment 
is intended to contain discharged oil so that it does not leave the 
facility and contaminate the environment. The proper method of 
secondary containment is a matter of good engineering practice, and so 
we do not prescribe here any particular method. Under part 112, where 
secondary containment is not practicable, you may deviate from the 
requirement, provide a contingency plan following the provisions of 40 
CFR part 109, and comply with the other requirements of Sec. 112.7(d). 
For bulk storage containers, those requirements include both periodic 
integrity testing of the containers and periodic integrity and leak 
testing of the valves and piping. You must also provide a written 
commitment of manpower, equipment, and materials to expeditiously 
control and remove any quantity of oil discharged that may be harmful.
    Applicability of requirement. Secondary containment is best for 
most facilities storing or using oil because it is the most effective 
method to stop oil from migrating beyond that containment. We believe 
that secondary containment is preferable to a contingency plan at 
manned and unmanned facilities because it prevents discharges as 
described in Sec. 112.1(b). At unmanned facilities, it may be even more 
important because of the lag in time before a discharge may be 
discovered. Notwithstanding what may be difficult terrain, we believe 
that some form of secondary containment is practicable at most 
facilities, including remote production facilities. In fact, it may 
often be more feasible in remote or rural areas because there are fewer 
space limitations in such areas. For example,

[[Page 47102]]

at some remote mobile or production facilities, owners or operators dig 
trenches and line them for containment or retention of drilling fluids. 
Technologies used at offshore facilities to catch or contain oil may 
also sometimes be used onshore.
    While some types of secondary containment (for example, dikes or 
berms) may not be appropriate at certain facilities, other types (for 
example, diversionary systems or remote impounding) might. However, we 
recognize and repeat, as we noted in the 1991 preamble, that some or 
perhaps all types of secondary containment for certain facilities with 
equipment that contain oil, such as electrical equipment, may be 
contrary to safety factors or other good engineering practice 
considerations. There might be other equipment, like fired or 
pressurized vessels, for which safety considerations also preclude some 
or all types of secondary containment.
    Some facilities or equipment that use but do not store oil may or 
may not, as a matter of good engineering practice, employ secondary 
containment. Such facilities might include wastewater treatment 
facilities, whose purpose is not to store oil, but to treat water. 
Other facilities that may not find the requirement practicable are 
those that use oil in equipment such as hydraulic equipment. Similarly, 
flowlines must have a program of maintenance to prevent discharges. See 
Sec. 112.9(d)(3). The maintenance program may or may not include 
secondary containment. Owners or operators of underground piping must 
have some form of corrosion protection, but do not necessarily have to 
use secondary containment for that purpose.
    As stated above, for a facility where secondary containment is not 
practicable, the owner or operator is not exempt from the requirement, 
but may instead provide a contingency plan and take other measures 
required under Sec. 112.7(d). For most facilities, however, including 
small facilities, mobile facilities, production facilities, mining 
sites, and any other facilities that store or use oil, we believe that 
secondary containment is generally necessary and appropriate to prevent 
a discharge as described in Sec. 112.1(b). Without secondary 
containment, discharges from containers would often reach navigable 
waters or adjoining shorelines, or affect natural resources.
    Methods of secondary containment. The appropriate method of 
secondary containment is an engineering question. Earthen or natural 
structures may be acceptable if they contain and prevent discharges as 
described in Sec. 112.1(b), including containment that prevents 
discharge of oil to groundwater that is connected to navigable water. 
What is practical for one facility, however, might not work for 
another. If secondary containment is not practicable, then the facility 
must provide a contingency plan following the provisions of 40 CFR part 
109, and otherwise comply with Sec. 112.7(d).
    Double-walled or vaulted tanks. The term ``vaulted tank'' has been 
used to describe both double-walled tanks (especially those with a 
concrete outer shell) and tanks inside underground vaults, rooms, or 
crawl spaces. While double-walled or vaulted tanks are subject to 
secondary containment requirements, shop-fabricated double-walled 
aboveground storage tanks equipped with adequate technical spill and 
leak prevention options might provide sufficient equivalent secondary 
containment as that required under Sec. 112.7(c). Such options include 
overfill alarms, flow shutoff or restrictor devices, and constant 
monitoring of product transfers. In the case of vaulted tanks, the 
Professional Engineer must determine whether the vault meets the 
requirements for secondary containment in Sec. 112.7(c). This 
determination should include an evaluation of drainage systems and of 
sumps or pumps which could cause a discharge of oil outside the vault. 
Industry standards for vaulted tanks often require the vaults to be 
liquid tight, which if sized correctly, may meet the secondary 
containment requirement.
    There might also be other examples of such alternative systems.
    Completely buried tanks. Completely buried tanks, other than those 
exempted from this rule because they are subject to all technical 
Federal or State UST requirements, are subject to the secondary 
containment requirement. We realize that the concept of freeboard for 
precipitation is inapplicable to secondary containment for completely 
buried tanks. The requirement for secondary containment may be 
satisfied in any of the ways listed in the rule or their equivalent.
    72-hour impermeability standard. We are withdrawing the proposal 
for the 72-hour impermeability standard and will retain the current 
standard that dikes, berms, or retaining walls must be sufficiently 
impervious to contain oil. We agree with commenters that the purpose of 
secondary containment is to contain oil from escaping the facility and 
reaching the environment. The rationale for the 72-hour standard was to 
allow time for the discovery and removal of an oil spill. An owner or 
operator of a facility should have flexibility in how he prevents a 
discharge as described in Sec. 112.1(b), and any method of containment 
that achieves that end is sufficient. Should such containment fail, the 
owner or operator must immediately clean up any discharged oil.
    Similarly, because the purpose of the ``sufficiently impervious'' 
standard is to prevent discharges as described in Sec. 112.1(b), dikes, 
berms, or retaining walls must be capable of containing oil and 
preventing such discharges. Discharges as described in Sec. 112.1(b) 
may result from direct discharges from containers, or from discharges 
from containers to groundwater that travel through the groundwater to 
navigable waters. Effective containment means that the dike, berm, or 
retaining wall must be capable of containing oil and sufficiently 
impervious to prevent discharges from the containment system until it 
is cleaned up. The same holds true for container floors or bottoms; 
they must be able to contain oil to prevent a discharge as described in 
Sec. 112.1(b). However, ``effective containment'' does not mean that 
liners are required for secondary containment areas. Liners are an 
option for meeting the secondary containment requirements, but are not 
required by the rule.
    If you are the owner or operator of a facility subject to this 
part, you must prepare a Plan in accordance with good engineering 
practice. A complete description of how secondary containment is 
designed, implemented, and maintained to meet the standard of 
sufficiently impervious is necessary. In order to document that 
secondary containment is sufficiently impervious and sufficiently 
strong to contain oil until it is cleaned up, the Plan must describe 
how the secondary containment is designed to meet that standard. A 
written description of the sufficiently impervious standard is not only 
necessary for design and implementation, but will aid owners or 
operators of facilities in determining which practices will be 
necessary to maintain the standard of sufficiently impervious. Control 
and/or removal of vegetation may be necessary to maintain the 
impervious integrity of the secondary containment. Repairs of 
excavations or other penetrations through secondary containment will 
need to be conducted in accordance with good engineering practices in 
order to maintain the standard of sufficiently impervious. The owner or 
operator should monitor such imperviousness for effectiveness, in order 
to be sure that the method chosen remains impervious to contain oil.

[[Page 47103]]

    Costs. We note that we have withdrawn the proposed 72 hour 
standard, and afford various secondary containment options, including 
earthen dikes and diked areas, if they contain and prevent discharges 
as described in Sec. 112.1(b). Therefore, there are no new costs. We 
disagree with the commenters who asserted that we underestimated the 
cost to comply with the secondary containment and truck loading and 
unloading area requirements. The revised rule, like the current rule, 
does not require a specific impermeability for dikes and does not 
require a specific method of secondary containment at loading and 
unloading areas, and this flexibility is reflected in our cost 
estimates. We noted in our 1991 Supplemental Cost/Benefit Analysis that 
secondary containment for bulk storage tanks is estimated to cost 
$1,000 for small facilities; $6,400 for medium facilities; and $63,000 
for large facilities. Unit cost estimates were developed for a broad 
mix of facilities (e.g., farms, bulk petroleum terminals) in each size 
category by experienced engineers with firsthand knowledge of the Oil 
Pollution Prevention Regulation and the operations of onshore SPCC-
regulated facilities. Because our cost estimates must be representative 
of the many types of facilities that are regulated, they will 
underestimate the costs for some facility types and overestimate the 
costs for others. Facilities were assumed to construct secondary 
containment systems of impervious soil capable of holding 110 percent 
of the largest tank. In that analysis, we estimated that 78 percent and 
88 percent of the regulated community were already in compliance with 
these requirements, respectively, and would not be affected by the 
proposed rule change.
    Since we last performed these analyses, API has issued several 
industry standards, including API 653 and 2610, which address many of 
the provisions in the SPCC rule. As a result, the final rule relies on 
current industry standards and practices, where feasible. In the final 
rule, we withdrew the proposed 72-hour impermeability standard for 
secondary containment and maintained the current requirement that 
dikes, berms, and oil retaining walls must be sufficiently impervious 
to contain oil. As a result, the final rule reflects current industry 
standards and we assume poses no additional requirements on industry.
    Sufficient freeboard. See the Response to Comments in 
Sec. 112.8(c)(2) for a discussion of this topic.
    Industry standards. Industry standards that may assist an owner or 
operator with secondary containment include: (1) NFPA 30; (2) BOCA, 
National Fire Prevention Code; and, (3) API Standard 2610, ``Design, 
Construction, Operation, Maintenance, and Inspection of Terminal and 
Tank Facilities.''
    Editorial changes and clarifications. In the introduction to 
paragraph (c), ``structures or equipment to prevent discharged oil from 
reaching a navigable water course'' becomes ``structures or equipment 
to prevent a discharge as described in Sec. 112.1(b).'' This wording 
change reflects the expanded scope of the CWA as reflected in 
Sec. 112.1(b) and is clearer than the proposed language. In the second 
sentence of the paragraph, we deleted the words ``permeate, drain, 
infiltrate, or otherwise'' from the sentence because they were 
unnecessary. The word ``escape'' in that sentence is sufficient. Also 
in that sentence, the reference to ``escape to surface waters'' becomes 
``escape from the containment system.'' This language more clearly 
reflects the intent of the rule that secondary containment should keep 
oil from escaping from the facility and reaching navigable waters or 
adjoining shorelines. In paragraph (c)(2)(i), ``curbing, drip pans'' 
becomes ``curbing or drip pans.''
    In response to the commenter's question, we note that a primary 
containment system is the container or equipment which holds oil or in 
which oil is used.

Section 112.7(d)--Contingency Planning

    Background. 1991 proposal. In 1991, we proposed to add several new 
requirements to the contingency planning requirement in Sec. 112.7(d). 
First, we proposed that a facility without secondary containment be 
required to test a tank for integrity every five years. In contrast, 
our 1991 proposal for Sec. 112.8(c)(6) provided for testing at least 
every 10 years for a tank with secondary containment. In addition, we 
proposed to require a facility without secondary containment to conduct 
integrity and leak testing of valves and piping at least annually. We 
also proposed that the contingency plan be submitted to the Regional 
Administrator for approval.
    Instead of referring to 40 CFR part 109 for contingency plan 
requirements as the current rule does, the 1991 proposal added specific 
requirements including a description of response plans; personnel 
needs; methods of mechanical containment; removal of spilled oil; and, 
access to and availability of sorbents, booms, and other equipment. 
Additionally, the proposal would have required that the Plan not rely 
on dispersants and other chemicals for response to oil spills without 
approval by the Regional Administrator. The owner or operator of a 
facility would also have been required to provide a written commitment 
of manpower, equipment, and materials required to quickly control and 
remove any quantity of oil that may be discharged.
    1993 proposal. In 1993, we modified the 1991 proposal for a 
facility that lacks secondary containment to require a facility 
response plan as described in Sec. 112.20, instead of the specific 
requirements proposed in 1991. The response plan would not be submitted 
to the Regional Administrator for his review, unless otherwise 
required, but would be maintained at the facility with the SPCC Plan.
    Comments. 1991 comments. Many commenters supported the 1991 
proposal. Opposing commenters suggested that such planning should be 
discretionary because not all facilities need such planning, or that 
facilities be allowed to use contingency plans prepared for other 
purposes. Others thought the proposal was premature as we had not at 
the time finalized response planning requirements in Sec. 112.20. One 
commenter argued that we should delete all of the contingency planning 
requirements in Sec. 112.7(d) at the point when we require an owner or 
operator to prepare a response plan. Some said that contingency 
planning was not practicable because the costs are too high, but 
commenters did not provide cost estimates. Several commenters 
criticized the proposed requirement that the contingency plan be 
submitted to the Regional Administrator, calling it duplicative, time-
consuming, and unnecessary. Two commenters suggested that the 
Contingency Plan prepared under RCRA rules would suffice. 
Representatives of small facilities asked for a small facility 
exemption. Others asked for clarification of what a ``written 
commitment'' of manpower, equipment, and materials meant. Several 
commenters asked if PE certification of the contingency plan was 
necessary. One commenter opposed any requirement to provide contingency 
planning for buried tanks, piping, or valves for which secondary 
containment cannot be provided.
    Integrity and leak testing. Several commenters supported the 
proposed integrity and leak testing requirements. Others opposed them, 
some on the basis that facilities already inspect their tanks 
regularly. Various commenters suggested exemptions for small containers 
or containers that are entirely within buildings. Electrical utilities 
argued that the requirement was

[[Page 47104]]

inapplicable for them because they do not store oil and that such 
testing would cause disruption in electrical service. Mining interests 
likewise asked for an exemption on the basis that they only store small 
amounts of oil and the requirements would be very expensive, but did 
not provide specific cost estimates. Various commenters asked for 
clarification of the term ``integrity testing,'' and its applicability. 
Others asked for clarification as to methods of testing. Some argued 
that testing of valves and gathering lines would be expensive and 
result in shut-downs of operations. None of these commenters provided 
specific cost estimates.
    1993 proposal. One commenter argued that the response plan proposal 
was beyond our statutory authority. Others argued that the proposal was 
expensive and lacking in environmental benefit. One commenter said that 
the installation of structures or measures achieving equivalent 
protection should be sufficient to avert the need for a response plan. 
Another suggested that the current rule, which specifies use of a 
strong oil spill contingency plan following 40 CFR part 109, is 
adequate. One commenter asked for an exemption for facilities in areas 
historically not subject to natural disasters. Electrical utility 
commenters asked for an exemption because they argued that a response 
plan was unnecessary for facilities that use, but do not store, oil.
    Response to comments. Planning requirements. We note that we did 
not finalize the 1991 or 1993 contingency planning proposals. Thus 
there are no new costs for such planning.
    Under the current rule, contingency planning is necessary whenever 
you determine that a secondary containment system for any part of the 
facility that might be the cause of a discharge as described in 
Sec. 112.1(b) is not practicable. This requirement applies whether the 
facility is manned or unmanned, urban or rural, and for large and small 
facilities. In response to comment, we have revised the rule to exempt 
from the contingency planning requirement any facility which has 
submitted a response plan under Sec. 112.20 because such a response 
plan is more comprehensive than a contingency plan following part 109.
    We believe that it may be appropriate for an owner or operator to 
consider costs or economic impacts in determining whether he can meet a 
specific requirement that falls within the general deviation provision 
of Sec. 112.7(a)(2). We believe so because under this section, the 
owner or operator will still have to utilize good engineering practices 
and come up with an alternative that provides ``equivalent 
environmental protection.'' However, we believe that the secondary 
containment requirement in Sec. 112.7(d) is an important component in 
preventing discharges as described in Sec. 112.1(b) and is 
environmentally preferable to a contingency plan prepared under 40 CFR 
part 109. Thus, we do not believe it is appropriate to allow an owner 
or operator to consider costs or economic impacts in any determination 
as to whether he can satisfy the secondary containment requirement. 
Instead, the owner or operator may only provide a contingency Plan in 
his SPCC Plan and otherwise comply with Sec. 112.7(d). Therefore, the 
purpose of a determination of impracticability is to examine whether 
space or other geographic limitations of the facility would accommodate 
secondary containment; or, if local zoning ordinances or fire 
prevention standards or safety considerations would not allow secondary 
containment; or, if installing secondary containment would defeat the 
overall goal of the regulation to prevent discharges as described in 
Sec. 112.1(b).
    We disagree that facility response planning is beyond our statutory 
authority, it is a procedure or method to remove discharged oil. See 
section 311(j)(1)(A) of the CWA. However, while we disagree that such 
planning is expensive and lacking in environmental benefit, we agree 
that the current contingency plan arrangements which reference 40 CFR 
part 109 should be sufficient to protect the environment, and that a 
facility response plan as described in Sec. 112.20 is therefore 
unnecessary for a facility that is not otherwise subject to 
Sec. 112.20. We agree with the commenter that structures or equipment 
might achieve the same or equivalent protection as response planning 
for some SPCC facilities. Therefore, we are withdrawing that part of 
the 1993 proposal related to response planning in proposed 
Sec. 112.7(d)(1), but are retaining the current contingency planning 
provisions, which require a contingency plan following the provisions 
of 40 CFR part 109. We also believe that response plans should be 
reserved for higher risk facilities, as provided in Sec. 112.20.
    In following the provisions of part 109, you must address the oil 
removal contingency planning criteria listed in 40 CFR 109.5 and ensure 
that all response actions are coordinated with governmental oil spill 
response organizations. The absence of secondary containment will place 
extreme importance on the early detection of an oil discharge and rapid 
response by the facility to prevent that discharge. Part 109 was 
originally promulgated to assist State and local government oil spill 
response agencies to prepare oil removal contingency plans in the 
inland response zone, where EPA provides the On-Scene Coordinator. The 
basic criteria for contingency planning listed in Sec. 109.5 apply to 
any SPCC regulated facility that has adequately justified the 
impracticability of installing secondary containment, irrespective of 
whether it is a government agency or the facility is located in the 
coastal (U.S. Coast Guard) or inland (EPA) response zone. Because the 
contingency plan involves good engineering practice and is technically 
a material part of the Plan, PE certification is required.
    A contingency plan prepared under RCRA rules might suffice for 
purposes of the rule if the plan fulfills the requirements of part 109, 
and the PE certifies that such plan is adequate for the facility. If 
the RCRA contingency plan satisfies some but not all SPCC requirements, 
you must supplement it so that it does.
    We note that the preamble to the 1993 proposed rule (at 58 FR 8841) 
suggested that response plans would not have to be submitted to the 
Regional Administrator unless ``otherwise required by the rest of 
today's proposed rule.'' However, proposed Sec. 112.7(a)(2) would have 
required that the owner or operator submit to the Regional 
Administrator any Plan containing a proposed deviation, including a 
deviation for the general secondary containment requirements in 
Sec. 112.7(c). In any case, we agree with commenters that the 
contingency plan (or any other deviation) should not have to be 
submitted to the Regional Administrator for his review and approval 
because we believe that it is sufficient that the contingency plan (or 
other deviation) be available for on-site inspection. We have therefore 
withdrawn that part of the proposal. See also the discussion on 
Sec. 112.7(a)(2).
    Integrity and leak testing. In response to a commenter who asked 
for a clarification of integrity testing, ``integrity testing'' is any 
means to measure the strength (structural soundness) of the container 
shell, bottom, and/or floor to contain oil and may include leak testing 
to determine whether the container will discharge oil. Facility 
components that might cause a discharge as described in Sec. 112.1(b) 
include containers, piping, valves, or other equipment or devices. 
Integrity testing includes, but is not limited to, testing foundations 
and supports of containers. Its scope includes both the

[[Page 47105]]

inside and outside of the container. It also includes frequent 
observation of the outside of the container for signs of deterioration, 
leaks, or accumulation of oil inside diked areas. Such testing is also 
applicable to valves and piping. See API Standard 653 for further 
information on this term.
    Leak testing for purposes of the rule is testing to determine the 
liquid tightness of valves and piping and whether they may discharge 
oil. Facilities that store oil, whether they are mines or other 
businesses, are required to employ integrity testing for their bulk 
storage containers, and integrity and leak testing for their valves and 
piping, to help prevent discharges. Containers that do not store oil, 
but merely use oil, are not subject to the requirement.
    We reaffirm the applicability of integrity and leak testing to both 
large and small facilities, because we believe such testing 
requirements help prevent discharges as described in Sec. 112.1(b) at 
those facilities. However, we have modified our proposal in response to 
comments to only require such testing on a periodic basis instead of at 
a prescribed frequency. Integrity and leak testing requirements are 
also applicable for containers and valves and piping that are entirely 
within buildings, or within mines, because in either case, such 
containers, or valves and piping may become the source of a discharge 
as described in Sec. 112.1(b). We have revised the rule to reflect that 
the requirement applies only to onshore and offshore bulk storage 
facilities. Therefore, a facility with only oil-filled electrical, 
operating, or manufacturing equipment need not conduct such testing nor 
incur any costs for such testing. For other types of facilities, we 
disagree that testing of valves and gathering lines would be 
prohibitively costly. In 1991, we estimated tank integrity testing and 
leak testing costs of buried piping. We estimated the costs as $465 per 
tank, $155 for equipment, and $310 for installation. Small facilities 
were assumed to have no buried piping. Medium sized facilities were 
assumed to bear first year costs for tank installation and testing of 
$4,704 and subsequent year costs of $1,449. Large facilities were 
assumed to incur a first year cost of $11,313, and subsequent year 
costs of $3,519. We assume that this provision represents a negligible 
additional burden because most facilities are already testing such 
valves and gathering lines according to industry standards as a matter 
of good engineering practice. We believe that if such testing is done 
in accordance with industry standards, costs will be minimized.
    We have eliminated the proposed frequency of the testing, both for 
containers and for valves and piping, in favor of testing according to 
industry standards. Instead, we require ``periodic'' integrity testing 
of containers, and ``periodic'' integrity and leak testing of valves 
and piping. ``Periodic'' testing means testing according to a regular 
schedule consistent with accepted industry standards. We believe that 
use of industry standards, which change over time, will prove more 
feasible than providing a specific and unchanging regulatory 
requirement. As required by Sec. 112.8(c)(6), integrity testing of 
containers must be accomplished by a combination of visual testing and 
some other technique.
    Written commitment. A ``written commitment'' of manpower, 
equipment, and materials means either a written contract or other 
written documentation showing that you have made provision for those 
items for response purposes. Such commitment must be shown by: the 
identification and inventory of applicable equipment, materials, and 
supplies which are available locally and regionally; an estimate of the 
equipment, materials, and supplies which would be required to remove 
the maximum oil discharge to be anticipated; and, development of 
agreements and arrangements in advance of an oil discharge for the 
acquisition of equipment, materials, and supplies to be used in 
responding to such a discharge. 40 CFR 109.5(c).
    The commitment also involves making provisions for well defined and 
specific actions to be taken after discovery and notification of an oil 
discharge including: specification of an oil discharge response 
operating team consisting of trained, prepared, and available operating 
personnel; predesignation of a properly qualified oil discharge 
response coordinator who is charged with the responsibility and 
delegated commensurate authority for directing and coordinating 
response operations and who knows how to request assistance from 
Federal authorities operating under current national and regional 
contingency plans; a preplanned location for an oil discharge response 
operations center and a reliable communications system for directing 
the coordinated overall response actions; provisions for varying 
degrees of response effort depending on the severity of the oil 
discharge; and, specification of the order of priority in which the 
various water uses are to be protected where more than one water use 
may be adversely affected as a result of an oil discharge and where 
response operations may not be adequate to protect all uses. 40 CFR 
109.5(d).
    Industry standards. Industry standards that may assist an owner or 
operator with the integrity testing of containers, and the integrity 
and leak testing of piping and valves include: (1) API Standard 653, 
``Tank Inspection, Repair, Alteration, and Reconstruction''; (2) API 
Recommended Practice 575, ``Inspection of Atmospheric and Low-Pressure 
Tanks''; (3) API Standard 570, ``Piping Inspection Code (Inspection, 
Repair, Alteration, and Rerating of In-Service Piping Systems)''; (4) 
American Society of Mechanical Engineers (ASME) B31.3, ``Process 
Piping''; (5) ASME 31.4, ``Liquid Transportation Systems for 
Hydrocarbons, Liquid Petroleum Gas, Anhydrous Ammonia, and Alcohols''; 
(6) Steel Tank Institute Standard SP001-00, ``Standard for Inspection 
of In-Service Shop Fabricated Aboveground Tanks for Storage of 
Combustible and Flammable Liquids''; and, (7) Underwriters Laboratory 
(UL) Standard 142, ``Steel Aboveground Tanks for Flammable and 
Combustible Liquids.''
    Editorial changes and clarifications. In the introductory 
paragraph, ``tanks'' becomes ``containers.'' We revised the first 
sentence of the introduction which now reads, ``When it is determined * 
* *,'' to read, ``If you determine * * *.'' Later in that sentence we 
change the words ``demonstrate such impracticability'' to ``explain why 
such measures are not practicable,'' in referencing the 
impracticability of secondary containment. Also, in the first sentence 
of the introduction, we clarify that the requirement for contingency 
planning and other measures is applicable when secondary containment is 
not practicable under Secs. 112.8(c)(2), 112.8(c)(11), 112.9(c)(2), 
112.10(c), 112.12(c)(2), 112.12(c)(11), 112.13(c)(2), and 112.14(c), as 
well as Sec. 112.7(c) and (h)(1). Additionally in that sentence, the 
reference to ``prevent discharged oil from reaching navigable waters'' 
becomes ``to prevent a discharge as described in Sec. 112.1(b),'' 
conforming the geographic scope of the rule to the CWA. At the end of 
the paragraph we clarify that when secondary containment is not 
practicable, the contingency plan and written commitment must be 
provided in the Plan, rather than to the Regional Administrator. We 
also clarify that if you have submitted a facility response plan under 
Sec. 112.20 for a facility, you need not provide for that facility 
either a contingency plan following the provisions of part 109, nor a 
written commitment of manpower, equipment, and materials required to 
expeditiously

[[Page 47106]]

control and remove any quantity of oil discharged that may be harmful.
    In paragraph (d)(1), ``A strong oil spill contingency plan 
following the provision of 40 CFR part 109 * * *.'' becomes ``An oil 
spill contingency plan following the provisions of part 109 * * *.'' 
The word ``strong'' is unnecessary because in any case the contingency 
plan must follow the provisions of part 109.
    In paragraph (d)(2), we did not finalize the proposed 
recommendation for the operator to consider financial capability in 
making his written commitment of manpower, equipment, and materials 
because we do not wish to confuse the regulated community with 
discretionary requirements in a mandatory rule. Finally, we changed the 
reference in paragraph (d)(2) from ``to expeditiously control and 
remove any harmful quantity of oil discharged'' to read ``to 
expeditiously control and remove any quantity of oil discharged that 
may be harmful.'' We made this change to refer to the statutory 
standard referring to a quantity of oil ``that may be harmful.''

Section 112.7(e)--Inspections, Tests, and Records

    Background. In 1991, we proposed that records and inspections and 
test results be kept for a period of five years. Current rules require 
record, inspection, and test results be maintained for three years. We 
also proposed that such records might be maintained with the Plan, 
instead of being part of the Plan.
    In 1997, we returned to the three-year record maintenance period in 
our new proposal. In 1997, we also proposed that usual and customary 
business records, such as records maintained under API Standards 653 
and 2610, would suffice to meet the requirements of this section. 
Finally we proposed that such records be made a part of the Plan.
    Comments. 1991 comments. Maintenance with Plan. Most commenters 
favored the proposal that records might be maintained with the Plan, 
rather than as part of it. Two commenters thought the requirements 
should apply generally only to large facilities.
    Form of records. One commenter urged use of electronic records.
    Records required. Still another asked that we list all inspections 
and tests required by part 112. One commenter asked for a requirement 
to keep records and tests of all major repairs and of employee 
training.
    Time period. Most commenters favored retaining the current three-
year time period to maintain records, believing it is adequate. Some 
commenters objected to the cost of a five-year record retention 
requirement. One commenter favored a two-year record maintenance 
period. Several favored a phase-in period if five years were to be 
required so that three-year records could be brought into compliance 
with the rule. One commenter favored a requirement that records be 
maintained in accordance with other State and Federal agency 
requirements to avoid additional and unnecessary costs.
    1997 comments. Maintenance with Plan. A number of commenters 
criticized the proposal that records must be maintained as part of the 
Plan, rather than maintained with the Plan, considering that proposal 
burdensome and providing no benefit to the environment.
    Form of records. Several commenters asked that we clarify that use 
of records maintained under the API standards cited is not required. 
Another commenter noted that many smaller companies do not use API 
standards, and that use of such records should be allowed ``when 
available.'' Several commenters urged that we state that records kept 
under the NPDES program might suffice for the SPCC program. Other 
commenters asked whether records in other formats might be acceptable, 
such as under a facility's QS-9000 or ISO-14000 system, or under 
standards promulgated by the Underwriters' Laboratories. Other 
commenters discussed use of NPDES stormwater bypass records. We will 
talk about those records under the discussion of Sec. 112.8(c)(3)(iv).
    Time period. Most commenters favored the proposal to retain the 
current three-year time period for maintenance of records.
    Response to comments. Maintenance with Plan. We agree with 
commenters that it is not necessary to maintain records as part of the 
Plan. Therefore, today's rule allows ``keeping'' of the records 
``with'' the Plan, but not as part of it. In the current rule, such 
records ``should be made part of the SPCC Plan * * *.'' 40 CFR 
112.7(e)(8). Because you continually update these records, this change 
will eliminate the need to amend your Plan each time you remove old 
records and add new ones. You still retain the option of making these 
records a part of the Plan if you choose.
    Records required. The rule permits use of usual and customary 
business records, and covers all of the inspections and tests required 
by this part as well as any ancillary records. ``Inspections and 
tests'' include not only inspections and tests, but schedules, 
evaluations, examinations, descriptions, and similar activities 
required by this part. After publication of this rule, we will list all 
of the inspections and tests required by part 112 on our website 
(www.epa.gov/oilspill). The applicability of each inspection and test 
will depend on the exercise of good engineering practice, because not 
every one will be applicable to every facility.
    Form of records. Records of inspections and tests required by this 
rule may be maintained in electronic or any other format which is 
readily accessible to the facility and to EPA personnel. Usual and 
customary business records may be those ordinarily used in the 
industry, including those made under API standards, Underwriters' 
Laboratories standards, NPDES permits, a facility's QS-9000 or ISO-
14000 system, or any other format acceptable to the Regional 
Administrator. If you choose to use records associated with compliance 
with industry standards, such as Underwriters' Laboratories standards, 
you must closely review the inspection, testing, and recordkeeping 
requirements of this rule to ensure that any records kept in accordance 
with industry standards meets the intent of the rule. Some standards 
have limited recordkeeping requirements and may only address a 
particular aspect of container fabrication, installation, inspection, 
and operation and maintenance. The intent of the rule is that you will 
not have to maintain duplicate sets of records when one set has already 
been prepared under industry or regulatory purposes that also fully 
suffices for SPCC purposes. The use of these alternative record formats 
is optional; you are not required to use them, but you may use them.
    Time period. We agree with commenters that maintenance of records 
for three years is sufficient for SPCC purposes, since that period will 
allow for meaningful comparisons of inspections and tests taken. 
Therefore, there will be no new costs. We note, however, that certain 
industry standards, for example API Standards 570 and 653, may specify 
record maintenance for more than three years.
    Editorial changes and clarifications. As proposed in 1991, we 
affirm that the certifying engineer, as well as the owner or operator, 
may be a person who develops inspection procedures. We also affirm that 
the provision applies to both ``inspections'' and ``tests'' undertaken. 
The tests are usually integral parts of the inspections.

[[Page 47107]]

Section 112.7(f)--Employee Training and Discharge Prevention Procedures

    Background. In 1991, we proposed that you conduct training 
exercises and that you train new employees within their first week of 
work. The rationale for these provisions was that a high percentage of 
discharges are caused by operator error; therefore, training and 
briefings might help prevent many discharges and promote a safer 
facility. This rationale was based on program experience and studies 
EPA undertook. The 1995 SPCC Survey found that operator error was the 
most common spill cause for facilities in 9 of the 19 industry 
categories that reported having spills. Also, the August 1994 draft 
report of the EPA Aboveground Oil Storage Facilities Workgroup called 
``Soil and Ground Water Contamination from Aboveground Oil Storage 
Facilities: A Strategic Study'' presented data on causes of discharges 
from two studies. Both studies showed that error during product 
transfer activities is one of the biggest known causes of discharges at 
AST facilities. Two other studies also support our contention: Carter, 
W.J., ``How API Viewed the Needs for Aboveground Storage Tanks,'' Tank 
Talk, Vol. 7, July/August 1992, p.2.; and U.S. EPA, ``The Technical 
Background Document to Support the Implementation of OPA Response Plan 
Requirements,'' Emergency Response Division, Office of Solid Waste and 
Emergency Response, February 1993, p.4-19.
    In 1993, we proposed to qualify the applicability of the training 
requirements to only those facilities that transfer or receive greater 
than or equal to 10,000 gallons of oil in a single operation more than 
twice per month on average, or greater than or equal to 50,000 gallons 
in a single operation more than once a month on the average. We further 
proposed that you require that employees involved in ``oil-handling 
activities,'' such as the operation or maintenance of oil storage tanks 
or the operation of equipment related to storage tanks, receive eight 
hours of facility specific training within one year of the effective 
date of the rule or at the date that your facility becomes subject to 
the requirement. In subsequent years, each employee would be required 
to undergo four hours of refresher training.
    Our 1993 proposal would require training for new employees within 
one week of employment. We also proposed to specify the areas in which 
you would be required to train employees to include: training in 
correct equipment operation and maintenance, general facility 
operations, discharge prevention laws and regulations, and the contents 
of the facility's SPCC Plan. Finally, the proposal would require that 
you conduct unannounced drills, at least annually, in which oil-
handling personnel would participate.
    Comments. 1991 comments. Applicability of training requirements. 
Numerous commenters suggested that the training requirements should 
apply only to personnel involved in the operation or maintenance of 
equipment. They argued that the training requirements need not apply to 
clerks, secretaries, and similar employees who are not involved in the 
physical operations of the facility. They also argued that we failed to 
sufficiently account for training costs in our economic analysis. 
Another commenter asked for a small facility exemption from training 
requirements.
    Another commenter asked that facilities be allowed to incorporate 
SPCC training requirements into already existing training programs 
required by other Federal or State law. One commenter suggested that 
the rule include a requirement that owners or operators document each 
training session and spill response drill conducted, and to maintain 
those records for five years.
    Timing of employee training. Some commenters favored the proposed 
provision for yearly training exercises and suggested that the training 
be coordinated with local oil spill response organizations or Local 
Emergency Planning Committees (LEPCs) whenever possible. One commenter 
cautioned that the annual training should not be considered a full 
scale SPCC drill.
    Opposing commenters suggested no time period for such exercises, or 
alternative periods, such as every two or three years.
    Likewise, many commenters opposed the provision relating to the 
training of new employees within one week of employment. Opposing 
commenters argued generally that such a recommendation is impractical, 
and called for employer discretion in scheduling training. Others 
suggested varying time periods in lieu of one week. Those suggestions 
ranged from one month to one year, with alternatives suggested such as 
``as soon as practical,'' ``prior to operation but before one year,'' 
``within one week of job assignment,'' ``a more reasonable time 
period,'' ``after training,'' and ``until the next annual training for 
all employees.'' One commenter asked that we define the term ``new 
employee.''
    Discharge prevention briefings. Many commenters criticized the 
proposal for annual spill prevention briefings, as opposed to the 
current requirement to hold such briefings ``at intervals frequent 
enough to assure adequate understanding of the SPCC Plan.'' They argued 
that the current standard is adequate. Some commenters suggested that 
we require additional training in these briefings such as emergency 
response training, or training concerning Plan changes.
    1993 comments. Applicability of training requirements. In 1993, 
many commenters asked for clarification of what ``oil-handling'' 
personnel meant. Some thought the requirements for training should be 
limited to those employees engaged in response activities. Others 
questioned what ``on average'' meant in determining the threshold 
applicability of the rule. Still others asked what ``a single 
operation'' meant. Some asked that the requirements be limited to 
facilities with potential to cause ``substantial harm'' to the 
environment. Others asked that the requirements be relaxed for 
facilities with equipment that reduce the potential for discharges. 
Some suggested differing gallon thresholds for the applicability of the 
training requirements. One commenter suggested that training be limited 
to those employees involved in emergency response or countermeasure 
activities. One commenter asked for an exemption from this requirement 
for small facilities. Another commenter asked for an exemption for 
extraction facilities, because, he argued, they have few spills. 
Another commenter suggested that the 1991 proposal was adequate.
    Timing of employee training. Some commenters favored the proposed 
requirement for eight-hour annual training, with four-hour refresher 
training in subsequent years. Others opposed it, arguing that employer 
discretion in this matter will ensure a better result.
    Likewise many commenters opposed the requirement that new employees 
be trained within one week of employment, arguing instead for employer 
discretion. Some commenters suggested alternate frequencies other than 
one week, ranging from ``prior to assuming duties'' to up to six months 
after hiring.
    Content of training. A few commenters supported the specification 
of training subjects. Some commenters suggested that we require 
training in the proper operation and maintenance of facility equipment 
and knowledge of spill procedure protocols. A utility commenter 
objected to the proposal that its employees be trained in maintenance 
of oil storage tanks, because its

[[Page 47108]]

maintenance activities do not involve the transfer or handling of oil 
and therefore fall outside the scope of the rule. Alternatively, the 
commenter suggested, those employees should be given a lower level of 
``awareness'' training. One commenter suggested inclusion of response 
training.
    Unannounced drills. Some commenters favored the proposal and 
suggested that actual discharge experience should be given credit as a 
drill. One commenter suggested a frequency schedule for various types 
of drills.
    Some commenters criticized the proposal for at least yearly 
unannounced drills. One commenter suggested that the frequency of the 
drills should be at the operator's discretion. Commenters argued that, 
if required at all, drills should only be applicable to operational or 
response personnel. Two commenters said that a requirement for 
unannounced drills for all employees would require them to conduct at 
least eight or more drills a year. Another commenter suggested training 
instead of drills, because of the potential for drills to cause 
expensive shutdowns.
    Response to comments. Applicability of training requirements. We 
believe that training requirements should apply to all facilities, 
large or small, including all those that store or use oil, regardless 
of the amount of oil transferred in any particular time. Training may 
help avert human error, which is a principal cause of oil discharges. 
``Spills from ASTs may occur as a result of operator error, for 
example, during loading operations (e.g., vessel or tank truck--AST 
transfer operation), or as a result of structural failure (e.g., 
brittle fracture) because of inadequate maintenance of the AST.'' EPA 
Liner Study, at 14. The 1995 SPCC Survey found that operator error was 
the most common spill cause for facilities in 9 of the 19 industry 
categories that reported having spills. Also, the August 1994 draft 
report of the EPA Aboveground Oil Storage Facilities Workgroup called 
``Soil and Ground Water Contamination from Aboveground Oil Storage 
Facilities: A Strategic Study'' presented data on causes of discharges 
from two studies. Both studies showed that error during product 
transfer activities is one of the biggest known causes of discharges at 
AST facilities. Two other studies also support our contention: Carter, 
W.J., ``How API Viewed the Needs for Aboveground Storage Tanks,'' Tank 
Talk, Vol. 7, July/August 1992, p.2.; and U.S. EPA, ``The Technical 
Background Document to Support the Implementation of OPA Response Plan 
Requirements,'' Emergency Response Division, Office of Solid Waste and 
Emergency Response, February 1993, p.4-19. We have therefore retained 
the applicability of training to all facilities. The 1993 proposal 
would have limited training requirements to only certain facilities 
which received or transferred over the proposed amount of oil. 
Facilities which receive or transfer less than the proposed amount 
might also have discharges which could have been averted through 
required training. Also the proposed rule would have exempted many 
facilities that use rather than store oil from its scope. Therefore, we 
have provided in the rule that all facilities, whether bulk storage 
facilities or facilities that merely use oil, must train oil-handling 
employees because all facilities have the potential for a discharge as 
described in Sec. 112.1(b), and training is necessary to avert such a 
discharge.
    We agree with the commenter that training is only necessary for 
personnel who will use it to carry out the requirements of this rule. 
Therefore revised paragraph (f)(1) provides that only oil-handling 
personnel are subject to training requirements, as we proposed in 1993. 
Thus there are no new training costs because we have always required 
such training of oil-handling personnel. ``Oil-handling personnel'' is 
to be interpreted according to industry standards, but includes 
employees engaged in the operation and maintenance of oil storage 
containers or the operation of equipment related to storage containers 
and emergency response personnel. We do not interpret the term to 
include secretaries, clerks, and other personnel who are never involved 
in operation or maintenance activities related to oil storage or 
equipment, oil transfer operations, emergency response, countermeasure 
functions, or similar activities.
    You may incorporate SPCC training requirements into already 
existing training programs required by other Federal or State law at 
your option or may conduct SPCC training separately.
    You must document that you have conducted required training 
courses. Such documentation must be maintained with the Plan for three 
years.
    Timing of employee training. We agree with commenters who thought 
it desirable to leave the timing and number of hours of training of 
oil-handling employees, including new employees, to the employer's 
discretion. ``Proper instruction'' of oil-handling employees, as 
required in the rule, means in accordance with industry standards or at 
a frequency sufficient to prevent a discharge as described in 
Sec. 112.1(b). This standard will allow facilities more flexibility to 
develop training programs better suited to the particular facility. 
While the rule requires annual discharge prevention briefings, we also 
agree that the annual briefings required are not drills. In any case, 
the SPCC rules do not require drills, as explained below.
    For purposes of the rule, it is not necessary to define a ``new 
employee'' because all oil-handling personnel are subject to training 
requirements, whether new or not. You do, however, have discretion as 
to the timing of that training, so long as the timing meets the 
requirements of good engineering practice.
    Discharge prevention briefings. Annual discharge prevention 
briefings are necessary, but there should be more frequent briefings 
where appropriate. Such briefings are necessary to refresh employees' 
memories on facility Plan provisions and to update employees on the 
latest prevention and response techniques. Training must include the 
contents of the facility Plan. Although it is desirable, we disagree 
that we should require SPCC briefings to include emergency response 
training. That training is already required for those facilities which 
must prepare response plans.
    Content of training. Specifying a minimum list of training subjects 
is necessary to ensure that facility employees are aware of discharge 
prevention procedures and regulations. As suggested by a commenter, we 
have added knowledge of discharge procedure protocols to the list of 
training subjects because such training will help avert discharges. 
Therefore, we have specified that training must include, at a minimum: 
the operation and maintenance of equipment to prevent the discharge of 
oil; discharge procedure protocols; applicable pollution control laws, 
rules, and regulations; general facility operations; and, the contents 
of the facility Plan. As noted above, we require response training for 
facilities that must submit response plans, but such training is not 
necessary for all SPCC facilities.
    In response to the utility commenter who asserted that utility 
employees do not need to be trained in the maintenance of oil storage 
tanks because such maintenance does not involve the transfer and 
handling of oil, we note that training must address relevant 
maintenance activities at the facility. If there is no transfer and 
handling of oil, such topic need not be covered in training.

[[Page 47109]]

    Unannounced drills. The proposed yearly frequency for unannounced 
drills is also unnecessary because such drills are already required at 
FRP facilities, which are higher risk facilities. We do not believe 
that the risk at all SPCC facilities approaches the same level as at 
FRP facilities. Therefore, we are not finalizing this proposal, and 
there are no new costs.
    Editorial changes and clarifications. We changed the title from 
``Personnel, training, and spill prevention procedures,'' to 
``Personnel, training, and discharge prevention procedures.'' In 
paragraph (f)(1), ``discharges of oil'' becomes ``discharges.'' In 
paragraph (f)(2), ``line management'' becomes ``facility management,'' 
and ``oil spill prevention'' becomes ``discharge prevention.'' In 
paragraph (f)(3), ``spill prevention briefings'' becomes ``discharge 
prevention briefings.'' Also in paragraph (f)(3); ``operating 
personnel'' becomes ``oil-handling'' personnel,'' to be consistent with 
language in paragraph (f)(1); and, ``spill events'' becomes 
``discharges as described in Sec. 112.1(b).''

Section 112.7(g)--Security (Excluding oil Production Facilities)

    Background. In 1991, we proposed to turn into a recommendation the 
current requirement that a facility should be fully fenced, and gates 
locked and/or guarded when the facility is not in production or is 
unattended. We proposed to require that the master flow and drain 
valves (or other valves that will permit direct outward flow of the 
tanks' contents) have adequate security to ensure that they remain in a 
closed position when in non-operating or non-standby status. Thus, the 
proposal would allow more flexibility in the method of securing the 
valves than the current rule, which requires that such valves be 
``securely locked.''
    The current rule requires that loading/unloading connections be 
securely capped or blank-flanged when not in service or standby-service 
``for an extended time.'' We proposed in 1991 to clarify that ``an 
extended time'' means six months or more, based on our Regional 
experience.
    Comments. Editorial changes and clarifications. One commenter asked 
for the meaning of ``plant'' as used in proposed Sec. 112.7(g)(1).
    Applicability of requirement. One commenter urged an exemption from 
all security provisions for mobile facilities, because such facilities 
are manned 24 hours a day while in operation.
    Fences. One commenter argued that fences should not be required for 
all facilities, because it is not practicable in some places. Another 
argued that fences should be topped with barbed wire, or otherwise 
designed to deter vandalism.
    Starter controls on pumps. Several commenters argued that the 
requirements to lock starter controls on all pumps and to locate them 
at a site accessible only to authorized personnel are duplicative and 
do not deter vandals or other unauthorized personnel. Another commenter 
urged us to exclude large facilities from the locking requirement 
because the potential for losing keys or having the locks become 
inoperative due to freezing conditions is great. A third commenter 
suggested that the requirement should apply to facilities, and not to 
pumps.
    Loading/unloading connections. One commenter urged that the blank-
flanging requirement apply to facilities that are not in service for 
six months or more, rather than to connections of oil piping. The 
rationale was that larger facilities have seasonal or contractual 
variations in use of lines, pumps, racks, and connections. Therefore, 
it would be costly and impractical to blank off lines only to reopen 
them in the seventh month. Accordingly, the rule should, per the 
commenter, recognize normal operating procedures at such facilities and 
allow flexibility. Another commenter requested that ``quick 
disconnect'' fittings qualify as a method of secure capping.
    Response to comments. Applicability of requirements. We asked in 
the 1991 preamble (at 56 FR 54616) for comments as to whether 
provisions proposed as discretionary measures or recommendations should 
be made requirements. We were concerned whether these proposed measures 
represented good engineering practice for all facilities. Specific 
comments are discussed below. In the case of proposed Sec. 112.7(g)(1) 
and (5) as requirements, we have decided to retain the requirements as 
requirements rather than convert those paragraphs into recommendations 
as proposed. We have done this because we believe that fencing, 
facility lighting, and the other measures prescribed in the rule to 
prevent vandalism are elements of good engineering practice in most 
facilities, including mobile facilities. Where they are not a part of 
good engineering practice, we have amended the proposed provision 
allowing deviations, Sec. 112.7(a)(2), to include the provisions in 
Sec. 112.7(g).
    Fences. Fencing helps to deter vandals and thus prevent the 
discharges that they might cause. In response to the commenter who 
argued that fences should be topped with barbed wire, or otherwise 
designed to deter vandalism, we agree. When you use a fence to protect 
a facility, the design of the fence should deter vandalism. Methods of 
deterring vandals might include barbed wire or other devices. If any 
type of fence is impractical, you may, under Sec. 112.7(a)(2), explain 
your reasons for nonconformance and provide equivalent environmental 
protection by some other means.
    Valves. Revised Sec. 112.7(g)(2) requires you to ensure that the 
master flow and drain valves and other valves permitting outward flow 
of the container's contents have adequate security measures. The 
current rule requires that such valves be securely locked in the closed 
position when in non-operating or non-standby status. Today's revised 
rule allows security measures other than locking drain valves or other 
valves permitting outflow to the surface. Manual locks may be 
preferable for valves that are not electronically or automatically 
controlled. Such locks may be the only practical way to ensure that 
valves stay in the closed position. For electronically controlled or 
automated systems, no manual lock may be necessary. The rule gives you 
discretion in the method of securing valves. We believe that this 
flexibility is necessary due to changes in technology and in the use of 
manual and electronic valving.
    Starter controls on pumps. We disagree that the requirements to 
have the starter control locked in the off position and be accessible 
only to authorized personnel are redundant. Restricting access to such 
pumps prevents unauthorized personnel from accidentally opening the 
starter control. These measures are necessary to prevent discharges at 
small as well as large facilities because the threat of discharge is 
the same regardless of the size of the container, and a small discharge 
may be harmful to the environment. If the potential for losing keys, 
weather conditions such as frequent freezing, or other engineering 
factors render such a measure infeasible, you may use the deviation 
provisions in Sec. 112.7(a)(2) if you can explain your reasons for 
nonconformance and provide equivalent environmental protection by some 
other means.
    Loading/unloading connections. In response to comment, we have 
decided to retain the current time line in Sec. 112.7(g)(4), i.e., ``an 
extended time,'' instead of specifying a six-month time line, due to 
the need for operational flexibility at facilities. We define ``an 
extended time'' in reference to industry standards or, in the absence 
of such standards, at a frequency sufficient to prevent any discharge. 
The appropriate method of securing or blank flanging of

[[Page 47110]]

these connections is a matter of good engineering practice, and might 
include ``quick disconnect fittings'' as a possible deviation under 
Sec. 112.7(a)(2). In any case, a secure cap is one equipped with some 
kind of lock or secure closure device to prevent vandalism. We disagree 
that the requirements of this paragraph should apply to the owner or 
operator of a facility instead of the owner or operator of the piping 
because a facility might place only some piping out of service for a 
period of time, and let other piping remain in service. Therefore, the 
owners or operators of some piping might escape the requirements of the 
rule and be more likely to discharge oil.
    Industry standards. Industry standards that may assist an owner or 
operator with security purposes include: (1) API Standard 2610, Design, 
Construction, Operation, Maintenance, and Inspection of Terminal and 
Tank Facilities; and, (2) NFPA 30A, Automotive and Marine Service 
Station Code, Flammable and Combustible Liquids Code.
    Editorial changes and clarifications. We agree that the term 
``plant'' has no clear meaning. Therefore, in paragraph (g)(1), we have 
substituted the term ``facility'' in its place, which is a defined term 
in these rules. Also in that paragraph, the phrase ``handling, 
processing and storing oil'' becomes ``handling, processing or storing 
oil.'' In paragraph (g)(2), ``tank'' becomes ``container.'' In 
paragraph (g)(3), ``pumps'' becomes ``pump.'' In paragraph (g)(5), the 
phrase ``Consideration should be given to:'' is deleted. We revise the 
sentence to read, ``Provide facility lighting commensurate with the 
type and location of the facility that will assist in the: * * *''

Section 112.7(h)--Loading/Unloading (Excluding Offshore Facilities)

    Background. In 1991, we reproposed the current discharge prevention 
requirements for loading/unloading racks.
    Comments. In general. Several commenters opposed the proposal on 
the basis that a requirement for a strong contingency plan would be a 
preferable and more effective alternative. Another commenter asked that 
we clarify that only facilities routinely used for loading or unloading 
of tanker trucks from or into aboveground bulk storage tanks are 
subject to this provision. One commenter believed that the proposed 
rule regulates items which ``should be covered'' by DOT rules governing 
loading, unloading, and vehicle inspection.
    Editorial changes and clarifications. One commenter asked for a 
clarification of the term ``quick drainage system.''
    Another commenter recommended that instead of mandatory containment 
requirements, a facility be allowed to show that procedures are in 
place to ensure that personnel are present at all times to supervise 
tank truck loading and unloading. Additionally, that commenter 
recommended that all new or renovated loading/unloading areas provide, 
at a minimum, curbing, sloped concrete, trenching, tanks, or basins 
which could contain at least five percent by volume of the largest 
compartment of the tank car or truck. For existing facilities, that 
commenter suggested that containment might contain a lesser volume, 
provided that the entire area is constructed of impervious material, no 
reported releases have occurred, and that loading/unloading activities 
are supervised.
    Alarm or warning systems. One commenter asked whether the 
requirement to provide a warning light or physical barrier system, or 
warning signs, applied to tank batteries or just plants. Another 
suggested that a vehicle brake interlock system or similar system might 
work just as well. Still another suggested the use of wheel chocks 
during tank truck transfers.
    Vehicle drain closure. Two commenters opposed the proposed 
requirement that vehicle drains and outlets be examined for leakage and 
if necessary repaired to prevent liquid leaks during transit. They 
argued that the facility owner had little or no control over trucks 
that were owned by others which loaded or unloaded at a facility and 
could not ensure their compliance with the rules.
    Response to comments. In general. This section is applicable to any 
non-transportation-related or terminal facility where oil is loaded or 
unloaded from or to a tank car or tank truck. It applies to containers 
which are aboveground (including partially buried tanks, bunkered 
tanks, or vaulted tanks) or completely buried (except those exempted by 
this rule), and to all facilities, large or small. All of these 
facilities have a risk of discharge from transfers. Our Survey of Oil 
Storage Facilities (published in July 1996) showed that as annual 
throughput increases, so does the propensity to discharge, the severity 
of the discharge, and, to a lesser extent, the costs of the cleanup. 
Throughput increases are often associated with transfers of oil.
    The requirements contained in this section, including those for 
secondary containment, warning systems, and inspection of trucks or 
cars for discharges are necessary to help prevent discharges. If you 
can justify a deviation for secondary containment requirement in 
paragraph (h)(1) on the basis that it is not practicable from an 
engineering standpoint, you must provide a contingency plan and take 
other actions to comply with Sec. 112.7(d). If you seek to deviate from 
any of the requirements in paragraphs (h)(2) or (3), you must explain 
your reasons for nonconformance, as provided in Sec. 112.7(a)(2), and 
provide measures affording equivalent environmental protection.
    We disagree that a contingency plan (whether labeled ``strong'' or 
otherwise) is a preferable alternative to secondary containment. 
Secondary containment is preferable because it may prevent a discharge 
that may be harmful as described in Sec. 112.1(b). A contingency plan 
is a plan for action when such discharge has already occurred. However, 
as noted earlier, if secondary containment is not practicable, you must 
provide a contingency plan and take other actions as required by 
Sec. 112.7(d). EPA will continue to evaluate the issue of whether the 
provisions for secondary containment found in Sec. 112.7(h)(1) should 
be modified or revised. We intend to publish a notice asking for 
additional data and comment on this issue.
    We disagree that the section regulates activities already under the 
purview of the U.S. Department of Transportation. We regulate the 
environmental aspects of loading/unloading transfers at non-
transportation-related facilities, which are legitimately part of a 
prevention plan. DOT regulates other aspects of those transfers, such 
as safety measures.
    Other State or Federal law. We have withdrawn, as unnecessary, 
proposed Sec. 112.7(h)(1), which would have required that facilities 
meet the minimum requirements of Federal and State law. Those 
requirements apply whether they are mentioned or not.
    Secondary containment. As noted above, the requirement for 
secondary containment applies to all facilities, whether with 
aboveground or completely buried containers. This includes production 
facilities and small facilities. The method of secondary containment 
must be one of those listed in the rule (see Sec. 112.7(c)), or some 
similar system that provides equivalent environmental protection. The 
choice of method is one of good engineering practice. However, in 
response to comments, we note that sumps and drip pans are a listed 
method of secondary containment for offshore facilities. A catchment 
basin might be an acceptable

[[Page 47111]]

form of retention pond for an onshore facility. Whatever method is 
implemented, it must be capable of containing the maximum capacity of 
any single compartment of a tank car or tank truck loaded or unloaded 
in the facility. A discharge from the maximum capacity of any single 
compartment of a tank car or tank truck includes a discharge from the 
tank car or tank truck piping and hoses. This is the largest amount 
likely to be discharged from the oil storage vehicle. A requirement 
that secondary containment be able to hold only five percent of a 
potential discharge when procedures are in place to prevent discharges 
fails to protect the environment if there is human error in one of 
those procedures. In case of discharge, the secondary containment 
system must be capable of preventing a discharge from that maximum 
capacity compartment to the environment. As mentioned above, if 
secondary containment is not practicable, you may be able to deviate 
from the requirement if you provide a contingency plan and otherwise 
comply with Sec. 112.7(d).
    Alarm or warning systems. The requirement to provide a warning 
light or other physical barrier system applies to the loading/unloading 
areas of facilities. We have amended the rule on the suggestion of a 
commenter to include ``vehicle brake interlock system'' and ``wheel 
chocks.'' The examples listed in the rule of potential warning systems 
are merely illustrative. Any other alarm or warning system which serves 
the same purpose and performs effectively will also suffice to meet 
this requirement.
    Vehicle drain closure. We believe that the requirement to check 
vehicles for discharge is important to help prevent discharges. If the 
check were not done, the entire contents of the vehicle might be 
discharged. We further believe that the responsibility for compliance 
with proposed Sec. 112.7(h)(3), as well as with all provisions of the 
rule, continues to rest with the owner or operator of the facility when 
those vehicles are loading or unloading oil at the facility.
    Industry standards. Industry standards that may assist an owner or 
operator with loading and unloading areas include: (1) NFPA 30, 
``Flammable and Combustible Liquids Code''; and, (2) API Standard 2610, 
``Design, Construction, Operation, Maintenance, and Inspection of 
Terminal and Tank Facilities.''
    Editorial changes and clarifications. In paragraph (h)(1), for 
clarity, ``plant'' is changed to ``facility.'' The phrase ``to handle 
spills'' becomes ``to handle discharges.'' A ``quick drainage system'' 
is a device which drains oil away from the loading/unloading area to 
some means of secondary containment or returns the oil to the facility. 
For Sec. 112.7(h)(1), if secondary containment is not practicable, you 
must provide a contingency plan following the provisions of 40 CFR part 
109, and otherwise comply with Sec. 112.7(d). Also, in paragraph 
(h)(1), ``tank truck'' becomes ``tank car or tank truck.'' In paragraph 
(h)(2), ``prevent vehicular departure,'' becomes ``prevent vehicles 
from departing.'' In paragraph (h)(3), ``leakage'' becomes 
``discharge.'' ``Discharge'' is a broader term, of which ``leakage'' is 
a subset. Also in that paragraph, ``examine'' becomes ``inspect.''

Section 112.7(i)--Brittle Fracture Evaluation

    Background. In 1993, we proposed to require that you evaluate your 
field-constructed tanks for brittle fracture if those tanks undergo 
repair, alteration, or a change in service. You would have been 
required to evaluate those tanks by adherence to industry standards 
contained in American Petroleum Institute (API) Standard 653, entitled 
``Tank Inspection, Repair, Alteration, and Reconstruction.'' The 
rationale was to help prevent the failure of field-constructed tanks 
due to brittle fracture, such as the four million gallon aboveground 
Ashland Oil tank failure which occurred in January 1988.
    Comments. Applicability. Several commenters favored the proposal. 
One suggested that we incorporate API Standard 653 into our rules to 
accommodate the possibility of tank failures other than through brittle 
fracture. One commenter opposed the proposal on the basis that the 
evaluation was unnecessary for small volume tanks and tanks with 
secondary containment. Other commenters argued that such testing was 
unnecessary for steel-bolted tanks because such tanks are too thin to 
be subject to brittle fracture since material properties are uniform 
through the thickness. One commenter asked that small facilities be 
exempted from the proposed requirement.
    Editorial changes and clarifications. Two commenters asked what the 
term ``change in service'' means. Others asked for clarification of the 
term ``field-erected tank.'' Another asked for clarification of the 
term ``repair,'' so that it would exclude ordinary day-to-day 
maintenance activities which are conducted to maintain the functional 
integrity of the tank and do not weaken the tank.
    Alternatives to brittle fracture evaluation. One commenter 
suggested that we allow testing by acoustic emission testing.
    Response to comments. Applicability. The requirement to evaluate 
field-constructed tanks for brittle fracture whenever a field-
constructed aboveground container undergoes repair, alteration, 
reconstruction, or change in service is necessary because brittle 
fracture may cause sudden and catastrophic tank failure, resulting in 
potentially serious damage to the environment and loss of oil. The 
requirement must be applicable to large and small facilities alike, 
because all the field-constructed aboveground containers have a risk of 
failure. The presence or absence of secondary containment does not 
eliminate the need for brittle fracture evaluation because the intent 
of the rule is to prevent a discharge whether or not it will be 
contained. While the requirement applies to all field-constructed 
aboveground containers, if you can show that the evaluation is 
unnecessary for your steel-bolted tanks, you may deviate from the 
requirement under Sec. 112.7(a)(2) if you can explain your reasons for 
nonconformance and provide equivalent environmental protection. We note 
that portions of steel-bolted tanks, such as the bottom or roof, may be 
welded, and therefore subject to brittle fracture.
    The requirement for evaluation of a field-constructed aboveground 
container must be undertaken when the container undergoes a repair, 
alteration, reconstruction, or change in service that might affect the 
risk of a discharge or failure due to brittle fracture, or when a 
discharge or failure has already occurred due to brittle fracture or 
other catastrophe. Catastrophic failures are failures which may result 
from events such as lightning strikes, dangerous seismic activity, etc. 
As a result of a catastrophic failure, the entire contents of a 
container may be discharged to the environment in the same way as if 
brittle fracture had occurred.
    ``Repair'' means any work necessary to maintain or restore a 
container to a condition suitable for safe operation. Typical examples 
include the removal and replacement of material (such as roof, shell, 
or bottom material, including weld metal) to maintain container 
integrity; the re-leveling or jacking of a container shell, bottom, or 
roof; the addition of reinforcing plates to existing shell 
penetrations; and the repair of flaws, such as tears or gouges, by 
grinding or gouging followed by welding. We understand that some 
repairs (such as repair of tank seals), alterations, or changes in 
service will not cause a risk of failure due to brittle

[[Page 47112]]

fracture; therefore, we have amended the rule to refer to those 
repairs, alterations, reconstruction, or changes in service that affect 
the risk of a discharge or failure due to brittle fracture.
    ``Alteration'' means any work on a container involving cutting, 
burning, welding, or heating operations that changes the physical 
dimensions or configurations of the container. Typical examples include 
the addition of manways and nozzles greater than 12-inch nominal pipe 
size and an increase or decrease in tank shell height.
    Alternatives to brittle fracture evaluation. We have eliminated the 
incorporation by reference to API Standard 653 from the rule. We have 
also therefore withdrawn proposed Appendix H, the API Standard 653 
brittle fracture flowchart. We believe that API Standard 653 is an 
acceptable standard to test for brittle fracture. However, an 
incorporation by reference of any standard might cause the rule to be 
instantly obsolete should that standard change or should a newer, 
better method emerge. A potential standard might also apply only to a 
certain subset of facilities or equipment. Therefore, as with most 
other requirements in this part, if you explain your reasons for 
nonconformance, alternative methods which afford equivalent 
environmental protection may be acceptable under Sec. 112.7(a)(2). If 
acoustic emission testing provides equivalent environmental protection 
it may be acceptable as an alternative. That decision, in the first 
instance, is one for the Professional Engineer and owner or operator.
    Industry standards. Industry standards that may assist an owner or 
operator with brittle fracture evaluation include: (1) API Standard 
653, ``Tank Inspection, Repair, Alteration, and Reconstruction''; and, 
(2) API Recommended Practice 920, ``Prevention of Brittle Fracture of 
Pressure Vessels.''
    Editorial changes and clarifications. A ``field-constructed 
aboveground container'' is one that is assembled or reassembled outside 
the factory at the location of its intended use. A ``change in 
service'' is a change from previous operating conditions involving 
different properties of the stored product such as specific gravity or 
corrosivity and/or different service conditions of temperature and/or 
pressure. The word ``reconstruction'' was added in the first sentence 
to conform with the text in API Standard 653. The words ``discharge 
or'' were added prior to ``failure'' and ``brittle fracture failure'' 
to make clear that evaluation is necessary when there has been a 
discharge from the container, whether or not there has been a complete 
failure of the container due to brittle fracture or catastrophe. When a 
container has failed completely and will be replaced, no brittle 
fracture or catastrophe evaluation is necessary. The evaluation is only 
applicable when the original container remains, but the physical 
condition of the container has changed due to repair, alteration, or 
change in service.

Section 112.7(j)--State Rules

    Background. In the introduction to Sec. 112.7(e) of the current 
rule, an owner or operator is required to discuss in the Plan his 
conformance with Sec. 112.7(c), plus other applicable parts of 
Sec. 112.7, other effective spill prevention and containment procedures 
or, if more stringent, with State rules, regulations, and guidelines. 
In our 1991 proposal, we limited the required discussion of ``other 
effective spill prevention and containment procedures'' to those listed 
in Secs. 112.8, 112.9, 112.10, and 112.11, or if more stringent, with 
State rules, regulations, and guidelines.
    Comments. Cross-referencing of requirements. One commenter argued 
that the proposed requirements should be more clearly limited to those 
sections which are applicable to the facility in question. For example, 
the commenter asserted, ``requirements in Sec. 112.8 `* * *onshore 
facilities (excluding production facilities)' should not (by the 
requirement in Sec. 112.7(i)) be applied to any portion of any 
production facility.''
    Consistency in rules. Two States urged that our rules be as 
consistent as possible with rules in the States. Another State urged 
that we grant reciprocity to State-approved Plans which have been 
reviewed under equal or greater adequacy criteria. One commenter 
complained that EPA rules are in some cases more stringent than some 
State rules.
    Federal and State regulation. Two commenters argued against any 
State regulation in the SPCC area to avoid duplication. Conversely, 
another commenter argued against any Federal regulation because the 
States are better qualified to regulate in the SPCC arena.
    Preemption. Another State requested that EPA strive to have similar 
programs as the States, or at the least not to preempt the States in 
the regulation of SPCC matters.
    Response to comments. Cross-referencing of requirements. In 
response to the commenter who believed that proposed Sec. 112.7(i) 
(redesignated in today's rule as Sec. 112.7(j)) might require him to 
discuss inapplicable requirements, we note that you must address all 
SPCC requirements in your Plan. You must include in your Plan a 
complete discussion of conformance with the applicable requirements and 
other effective discharge prevention and containment procedures listed 
in part 112 or any applicable more stringent State rule, regulation, or 
guideline. If a requirement is not applicable to a particular type of 
facility, we believe that it is important for an owner or operator to 
explain why.
    Consistency in rules. As noted above, you may now use a State plan 
as a substitute for an SPCC Plan when the State plan meets all Federal 
requirements and is cross-referenced. When you use a State plan that 
does not meet all Federal requirements, it must be supplemented by 
sections that do meet all Federal requirements. At times EPA will have 
rules that are more stringent than States rules, and some States may 
have rules that are more stringent than those of EPA. If you follow 
more stringent State rules in your Plan, you must explain that is what 
you are doing.
    Federal and State regulation. Both the States and EPA have 
authority to regulate containers storing or using oil. We believe State 
authority to regulate in this area and establish spill prevention 
programs is supported by section 311(o) of the CWA. Some States have 
exercised their authority to regulate while others have not. We believe 
that State SPCC programs are a valuable supplement to our SPCC program.
    Preemption. We do not preempt State rules, and defer to State 
rules, regulations, and guidelines that are more stringent than part 
112.
    Editorial changes and clarifications. To simplify the rule 
language, we have amended the proposed rule to state that you must 
discuss all applicable requirements in the Plan instead of listing all 
of the sections individually. The phrase ``sections of the Plan shall 
include* * *'' becomes ``include in your Plan* * * .'' ``Spill'' 
becomes ``discharge.''

Subpart B--Requirements for Petroleum Oils or Other Non-petroleum Oils, 
Except Animal Fats and Vegetable Oils

    Background. As noted above, we have reformatted the rule to 
differentiate between various classes of oil as mandated by EORRA. 
Subpart B prescribes particular requirements for an owner or operator 
of a facility that stores or uses petroleum oils or non-petroleum oils, 
except for animal fats and vegetable oils.

[[Page 47113]]

Introduction to Section 112.8

    Background. We have inserted an introduction to Sec. 112.8 so that 
we could list the requirements of that section in the active voice. 
Those requirements, except as specifically noted, apply to the owner or 
operator of an onshore facility (except a production facility). The 
introduction does not result in any substantive change in requirements.

Section 112.8(a)--General Requirements--Onshore Facilities (Excluding 
Production Facilities)

    Background. This is a new provision that merely references the 
general requirements which all facilities subject to this part must 
meet and the specific requirements that facilities subject to this 
section must meet. It does not result in any change to substantive 
requirements.
    Editorial changes and clarifications. ``Spill prevention'' in the 
1991 proposal becomes ``discharge prevention.'' We also deleted from 
the titles of each paragraph the words ``onshore'' and ``excluding 
production facilities'' because the entire section applies to onshore 
facilities and excludes production facilities from its scope. Finally, 
the proposed requirement to ``address'' general and specific 
requirements and procedures becomes ``meet'' those requirements and 
procedures.

Section 112.8(b)(1)--Diked Storage Area Drainage

    Background. In 1991, we reproposed the current rule 
(Sec. 112.7(e)(1)(i)) on facility drainage from diked areas.
    Comments. Applicability. One commenter asked that we limit the 
scope of this section to facilities having areas with the potential to 
receive discharges greater than 660 gallons or areas with tanks 
regulated under these rules. Another commenter said that for facilities 
with site-wide containment, or that have substantial stormwater 
draining onto and across the site, the requirement is not practical and 
may justify reliance on contingency plans instead of containment. That 
commenter, and another, suggested that certain devices may reduce the 
potential of a significant spill of floating or other products that can 
be separated by gravity, such as oil/water separators, underflow 
uncontrolled discharge devices, and other apparatus.
    De minimis amounts of oil. One commenter thought it would be 
impossible to ensure no oil would be discharged into water from diked 
areas. The rationale was that oil can be present in water in an amount 
below the perception threshold of the human eye.
    Response to comments. Applicability. We disagree that we should 
limit the scope of this section to facilities having areas with the 
potential to receive discharges greater than 660 gallons or areas with 
tanks regulated under these rules. Small discharges (that is, of 660 
gallons or less) as described in Sec. 112.1(b) from diked storage areas 
can cause great environmental harm. See section IV. F of this preamble 
for a discussion of the effects of small discharges. We disagree that 
this section should apply only to areas with tanks regulated under 
these rules because this rule applies to regulated facilities, not 
merely areas with regulated tanks or other containers. A facility may 
contain operating equipment within a diked storage area which could 
cause a discharge as described in Sec. 112.1(b).
    We disagree that the requirement is not practical for facilities 
with site-wide containment, or that have substantial stormwater 
draining onto and across the site. Where oil/water separators, 
underflow uncontrolled discharge devices, or other positive means 
provide equivalent environmental protection as the discharge restraints 
required by this section, you may use them, if you explain your reasons 
for nonconformance. See Sec. 112.7(a)(2). However, you must still 
ensure that no oil will be discharged when using alternate devices.
    De minimis amounts of oil. This rule is concerned with a discharge 
of oil that would become a discharge as described in Sec. 112.1(b). 
When oil is present in water in an amount that cannot be perceived by 
the human eye, the discharge might not meet the description provided in 
40 CFR 110.3. Therefore, such a discharge might not be a discharge in a 
quantity that may be harmful, and therefore not a reportable discharge 
under part 110. However, a discharge which is invisible to the human 
eye might also contain components (for example, dissolved petroleum 
components) which would violate applicable water quality standards, 
making it a reportable discharge. Therefore, we are keeping the 
language as proposed, other than making some editorial changes.
    Industry standards. Industry standards that may assist an owner or 
operator with facility drainage include: (1) NFPA 30, ``Flammable and 
Combustible Liquids Code''; and (2), API Standard 2610, ``Design, 
Construction, Operation, Maintenance, and Inspection of Terminal and 
Tank Facilities.''
    Editorial changes and clarifications. ``Spill or other excessive 
leakage of oil'' and ``leakage'' become ``discharge.'' The phrase 
``handle such leakage'' becomes ``control such discharge.'' We deleted 
the phrase ``or other positive means,'' because it is confusing when 
compared with the text of Sec. 112.7(a)(2). Under Sec. 112.7(a)(2), you 
have the flexibility to use alternate measures ensuring equivalent 
environmental protection. The word ``examine'' becomes ``inspect.''

Section 112.8(b)(2)--Diked Storage Areas--Valves Used; Inspection of 
Retained Stormwater

    Background. In 1991, we reproposed the current rule on the type of 
valves that must be used to drain diked storage areas. The rule also 
addresses inspection of retained stormwater.
    Comments. Innovative devices. Two commenters believed that the rule 
would apparently preclude the use of innovative containment devices to 
control discharges from containment dikes, such as imbiber beads. These 
beads are inside a small cylinder that filters releases from a 
containment area. The beads are inserted where a valve would be placed 
and allow water to pass, but prevent release of oil by closing on 
contact. Another commenter asked that the rule allow oil-water gravity 
separation systems instead of valves.
    PE certification. One commenter suggested that a section should be 
added to the rule requiring that Professional Engineers be required to 
certify the design and construction of the stormwater drainage system 
and the sanitary sewer system, because the Professional Engineer is in 
the best position to prepare the spill containment parts of the SPCC 
Plan.
    Response to comments. Innovative devices. This rule does not 
preclude innovative devices that achieve the same environmental 
protection as manual open-and-closed design valves. If you do not use 
such valves, you must explain why. The provision for deviations in 
Sec. 112.7(a)(2) allows alternatives if the owner or operator states 
his reasons for nonconformance, and if he can provide equivalent 
environmental protection by some other means. However, you may not use 
flapper-type drain valves to drain diked areas. And if you use 
alternate devices to substitute for manual, open-and-closed design 
valves, you must inspect and may drain retained stormwater, as provided 
in Sec. 112.8(c)(3)(ii), (iii), and (iv), if your facility drainage 
drains directly into a watercourse, lake, or pond bypassing the 
facility treatment system.
    PE certification. PE certification is already required for the 
design of

[[Page 47114]]

stormwater drainage and sanitary sewer systems by current rules because 
those systems are a technical element of the Plan. Therefore, we are 
keeping the language as proposed.
    Editorial changes and clarifications. In the first sentence, we 
deleted the phrase ``as far as practical'' because it is confusing when 
compared to the text of Sec. 112.7(a)(2). Under Sec. 112.7(a)(2), if 
the requirement is not practical, you have the flexibility to use 
measures ensuring equivalent environmental protection. In the second 
sentence, we clarify that the wastewater treatment plant mentioned 
therein is an ``on-site wastewater treatment plant.'' Also in that 
sentence, we clarify that you must inspect and ``may drain'' retained 
stormwater, as provided in Sec. 112.8(c)(3)(ii), (iii), and (iv). 
Finally, in the last sentence, we clarify that drained retained 
stormwater must be ``uncontaminated.''

Section 112.8(b)(3)--Drainage Into Secondary Containment; Areas Subject 
to Flooding

    Background. In 1991, we proposed to clarify that only undiked areas 
that are located such that they have a reasonable potential to be 
contaminated by an oil discharge are required to drain into a pond, 
lagoon, or catchment basin. We explained that a good Plan should seek 
to separate reasonably foreseeable sources of contamination and non-
contamination.
    We also proposed to make a recommendation of the current 
requirement that catchment basins not be located in areas subject to 
periodic flooding.
    Comments. One commenter supported the proposal.
    Editorial changes and clarifications. One commenter suggested that 
the rule should be worded to refer to systems ``with a potential for 
discharge,'' rather than with a ``potential for contamination.''
    Applicability. Two commenters argued that the secondary containment 
provisions of this paragraph should ``remain a recommendation as 
opposed to a regulation,'' because a requirement is impracticable for 
drainage systems from pipelines that move product throughout the 
facility.
    Alternatives. One commenter said that the rule should not be 
limited to drainage trenches, and that the owners and operators of 
facilities should have a free choice of design. Another commenter 
suggested that if areas under aboveground piping and loading/unloading 
areas are regulated under this section, the operation should have the 
option of providing spill control by committing to the regular 
inspection of, and immediate clean-up of spills within such areas. 
Another commenter urged that we clarify that oil/water separators meet 
the requirement for drainage control and secondary containment because 
such units, when properly sized and operated, meet the requirements of 
good engineering practice for preventing discharges of oil. One 
commenter suggested that in rural areas where electrical equipment is 
widely spaced, it may be more practical to provide for individual 
secondary containment rather than site-wide diversion facilities. Other 
commenters suggested that the drainage requirements in urban areas 
would be impossible to meet for transformers located in vaults in large 
office and apartment buildings, and underneath urban streets because 
there is no space at such sites to construct the sort of drainage 
control structures required by the rule.
    Areas subject to periodic flooding. One commenter argued that the 
proposed recommendation should be retained as a requirement because it 
is highly unlikely that catchment basins would operate effectively 
during a flood event, and that these facilities could cause significant 
harm to the environment. Another commenter suggested that drainage 
systems for existing facilities be engineered (even if it requires 
pumping of contaminated water to a higher level for storage prior to 
treatment) so that minimal amounts of contaminated water are retained 
in areas subject to periodic flooding.
    Response to comments. Applicability. We disagree that the rule 
language should become a recommendation because we believe that it is 
important to control the potential discharges the rule addresses. Where 
a drainage system is infeasible, if you explain your reasons for 
nonconformance, you may provide equivalent environmental protection by 
an alternate means.
    In response to the commenter who questioned the applicability of 
this paragraph to areas under aboveground piping and loading/unloading 
areas, we note that both areas are subject to the rule's requirements 
if they are undiked.
    Alternatives. The rule does not limit you to the use of drainage 
trenches for undiked areas. Other forms of secondary containment may be 
acceptable. The rule only prescribes requirements for the drainage of 
diked areas, but does not mandate the use of diked areas. However, if 
you do use diked areas, the rule prescribes minimum requirements for 
drainage of those areas. Also, if the requirement is not practical, you 
may explain your reasons for nonconformance and provide equivalent 
environmental protection under Sec. 112.7(a)(2).
    Areas subject to periodic flooding. We agree with the commenter 
that the current requirement should remain a requirement and not be 
converted into a recommendation. We are convinced by the argument that 
catchment basins will not work during flood events and may cause 
significant environmental damage. We also agree with the commenter that 
any drainage system should be engineered so that minimal amounts of 
contaminated water are retained in areas subject to periodic flooding. 
Therefore, we have retained the current requirement. We also recommend, 
but do not require that ponds, lagoons, or other facility drainage 
systems with the potential for discharge not be located in areas 
subject to periodic flooding.
    Editorial changes and clarifications. We agree that the wording 
``potential for discharge'' meets the intent of the rule better than 
``potential for contamination'' and have made that change.

Section 112.8(b)(4)--Diversion Systems

    Background. In 1991, we proposed that diversion systems must retain 
oil in the facility, rather than return it to the facility after it has 
been discharged.
    Comments. One commenter asked for a clarification that oil 
``retained'' in a facility does not leave the facility boundaries. A 
second commenter suggested that oil be either retained within the 
facility or returned to the facility, whichever is applicable. The 
commenter further suggested that the diversion system apply only to the 
petroleum areas of the facility such as tanks, pipes, racks, and diked 
areas because drainage from the rest of the facility should not be 
contaminated and thus should not have to be diverted.
    Response to comments. The rule accomplishes the aim of retaining 
within the facility minimal amounts of contaminated water in undiked 
areas subject to periodic flooding. It is better that a diversion 
system retain rather than allow oil to leave the facility, thus 
enhancing the prevention goals of the rule. Furthermore, it should be 
easier to retain discharged oil rather than retrieve oil that has been 
discharged from the facility. Therefore, we agree with the commenter 
that ``retained'' oil is oil that never leaves the facility. We also 
agree that the rule applies only to drainage from the ``petroleum'' (or 
other oil) areas of the facility such as tanks, pipes, racks, and diked 
areas, because the purpose of the SPCC rule is to prevent discharges of 
oil, not of all runoff contaminants. Amendment of the rule

[[Page 47115]]

language is unnecessary because all of the rule applies only to 
``petroleum'' or ``oil'' areas of the facility. Therefore, we have 
promulgated the rule language as proposed with a minor editorial 
change.
    Editorial changes and clarifications. We clarify that the reference 
to the engineering of facility drainage is a reference to paragraph 
(b)(3).

Section 112.8(b)(5)--Natural Hydraulic Flow, Pumps

    Background. In 1991, we reproposed substantively the current rule 
(see Sec. 112.7(e)(1)(v)) concerning hydraulic flow and pump transfer 
for drainage waters.
    Comments. We received one editorial comment regarding a grammatical 
error in the proposal. The commenter suggested that the second sentence 
of the proposal read, ``If pump transfer is needed, two ``lift'' pumps 
shall be provided, and at least one of the pumps shall be permanently 
installed when such treatment is continuous.'' We received no 
substantive comments.
    Editorial changes and clarifications. We deleted the first sentence 
from the proposed rule because it is a recommendation. We are not 
including recommendations in this rule so as to avoid confusion in the 
regulated community as to what is required and what is not. We agree 
with the commenter's editorial suggestion regarding the second 
sentence, and have amended the rule accordingly. In the last sentence 
of the proposal, the phrase ``oil will be prevented from reaching 
navigable waters of the United States, adjoining shorelines, or other 
waters that would be affected by discharging oil as described in 
Sec. 112.1(b)(1) of this part'' becomes `` to prevent a discharge as 
described in Sec. 112.1(b). * * *''
    Response to comments. We have corrected the grammatical error.

Proposed Section 112.8(b)(6)--Additional Requirements for Events that 
Occur During a Period of Flooding

    Background. In 1991, we proposed a new recommendation that 
facilities should address the need to comply with Federal, State, and 
local governmental requirements in areas subject to flooding. We noted 
that this recommendation was consistent with Federal Emergency 
Management Agency (FEMA) rules found at 44 CFR part 60 for aboveground 
storage tanks located in flood hazard areas.
    Comments. One commenter suggested that exploration and production 
tanks located in flood plain areas should be adequately secured through 
proper mechanical or engineering methods to reduce the chance of loss 
of product. Another commenter argued that the proposed rule should be 
eliminated because it is duplicative of stormwater regulations. One 
commenter urged that the rule require that no facilities for oil or 
hazardous substances be sited in floodplains. Another commenter 
requested that the rule require that: (1) A facility should identify 
whether it is in a floodplain in the SPCC Plan; (2) if it is in a 
floodplain, the Plan should address minimum FEMA standards; and, (3) if 
a facility does not meet minimum FEMA standards, the Plan should 
address appropriate precautionary and mitigation measures for potential 
flood-related discharges. The commenter also suggested that we consider 
requiring facilities in areas subject to 500-year events to address 
minimum FEMA standards. A second commenter supported a requirement for 
special considerations in the Plan for facilities in areas subject to 
flooding. That commenter also suggested that we define ``areas subject 
to flooding,'' and noted that other Federal rules (i.e., RCRA) define 
this as the 25-year floodplain. Another commenter thought the term 
``areas subject to flooding'' should be explained in terms of a 100-
year flood event. A final comment noted that the preamble spoke to a 
recommendation that facilities address precautionary measures if they 
are located in areas subject to flooding, while the recommendation text 
spoke to requirements for events that occur during a period of 
flooding. The commenter urged reconciliation of the differing language.
    Response to comments. We deleted this recommendation because it is 
more appropriately addressed in FEMA rules and guidance, including the 
definitions the commenters referenced. We disagree that the proposed 
recommendation should be made a requirement because flood control plans 
and design capabilities for discharge systems are provided for under 
the stormwater regulations, and further Federal regulations would be 
duplicative.
    Other Federal rules also apply, making further SPCC rules 
unnecessary. Oil storage facilities are considered structures under the 
National Flood Insurance Program (NFIP), and therefore such structures 
are subject to the Regulations for Floodplain Management at 44 CFR 
60.3. Some of the specific NFIP standards that may apply for 
aboveground storage tanks include the following: (1) tanks must be 
designed so that they are elevated to or above the base flood level 
(100-year flood) or be designed so that the portion of the tank below 
the base flood level is watertight with walls substantially impermeable 
to the passage of water, with structural components having the 
capability of resisting hydrostatic and hydrodynamic loads, and with 
the capability to resist effects of buoyancy (44 CFR 60.3(a)(3)); (2) 
tanks must be adequately anchored to prevent flotation, collapse or 
lateral movement of the structure resulting from hydrodynamic and 
hydrostatic loads and the effects of buoyancy (40 CFR 60.3(c)(3)); for 
structures that are intended to be made watertight below the base flood 
level, a Registered Professional Engineer must develop and/or review 
the structural design, specifications, and plans for construction, and 
certify that they have been prepared in accordance with accepted 
standards and practice (40 CFR 60.3(c)(4)); and, tanks must not 
encroach within the adopted regulatory floodway unless it has been 
demonstrated that the proposed encroachment would not result in any 
increase in flood levels within the community during the occurrence of 
the base flood discharge (40 CFR 60.3(d)). Additionally, the NFIP has 
specific standards for coastal high hazard areas. See 40 CFR 
60.3(e)(4).

Section 112.8(c)(1)--Construction of and Materials Used for Containers

    Background. In 1991, we reproposed without substantive change 
current Sec. 112.7(e)(2)(i), which requires that no tank be used for 
the storage of oil unless its material and construction are compatible 
with the material stored and the conditions of storage such as pressure 
and temperature. The only changes we proposed were editorial. We also 
proposed a new recommendation that the construction, materials, 
installation, and use of tanks conform with relevant industry standards 
such as API, NFPA, UL, or ASME standards, which are required in the 
application of good engineering practice for the construction and 
operation of the tank.
    Comments. Several commenters asked that the proposal be recast as a 
recommendation rather than a rule, arguing that the words of the 
proposal, when taken in conjunction with Sec. 112.7(a) language 
requiring the use of good engineering practice in the preparation of 
Plans, were contradictory. A commenter noted that Sec. 112.8(c)(1) 
recommends that materials, construction, and installation of tanks 
adhere to industry standards ``which are required in the application of 
good engineering practice for the construction and operation of the 
tank.'' The commenter asserted that since it is clear in the preamble 
that the Agency's intent is to make the use of industry standards a 
recommendation rather than a

[[Page 47116]]

requirement, the rule should be modified to reflect that. Another 
commenter supported the proposal as a requirement on the theory that 
all tanks should be required to meet industry standards. A third 
commenter asked for clarification as to whether we intended a 
recommendation or a requirement.
    One commenter asked that we specifically reference steel storage 
tank systems standards in the rule.
    Response to comments. Requirement v. recommendation. The first 
sentence of the proposed rule indeed contemplated a requirement, i.e., 
that no container may be used for the storage of oil unless its 
material and construction are compatible with the material stored and 
the conditions of storage, such as pressure or temperature. The second 
sentence, which was clearly a recommendation, has been deleted from the 
rule because we have decided to remove all recommendations from the 
rule language. Rules are mandates, and we do not wish to confuse the 
regulated community as to what actions are mandatory and what actions 
are discretionary. The Professional Engineer must, pursuant to 
Sec. 112.3(d)(1)(iii), certify that he has considered applicable 
industry standards in the preparation of the Plan. While he must 
consider such standards, use of any particular standards is a matter of 
good engineering practice.
    Industry standards. Industry standards that may assist an owner or 
operator with the material and construction of containers include: (1) 
API Standard 620, ``Design and Construction of Large Welded Low-
Pressure Storage Tanks''; (2) API Standard 650, ``Welded Steel Tanks 
for Oil Storage''; (3) Steel Tank Institute (STI) F911, ``Standard for 
Diked Aboveground Steel Tanks''; (4) STI Publication R931, ``Double 
Wall Aboveground Storage Tank Installation and Testing Instruction''; 
(5) UL Standard 58, ``Standard for Steel Underground Tanks for 
Flammable and Combustible Liquids''; (6) UL Standard 142, ``Steel 
Aboveground Tanks for Flammable and Combustible Liquids''; (7) UL 
Standard 1316, ``Standard for Glass-Fiber-Reinforced Plastic 
Underground Storage Tanks for Petroleum Products''; and, (8) Petroleum 
Equipment Institute (PEI) Recommended Practice 200, ``Recommended 
Practices for Installation of Aboveground Storage Systems for Motor 
Vehicle Fueling.''
    Editorial changes and clarifications. ``Bulk storage tanks'' 
becomes ``bulk storage containers.'' We deleted the abbreviation 
``etc.'' from the end of the paragraph because it is unnecessary. The 
use of the phrase ``such as pressure and temperature'' already 
indicates that these are only some examples of such conditions.

Section 112.8(c)(2)--Secondary Containment--Bulk Storage Containers

    Background. In 1991, we reproposed current secondary containment 
requirements with several significant additions. We gave notice in the 
preamble (at 56 FR 54622-23) that ``sufficient freeboard'' is freeboard 
sufficient to contain precipitation from a 25-year storm event. We also 
proposed in rule language that diked areas must be sufficiently 
impervious to contain spilled oil for at least 72 hours. The current 
standard is that such diked areas must be ``sufficiently impervious'' 
to contain spilled oil.
    Comments. Secondary containment, in general. One commenter asked 
for clarification of what ``primary containment system'' means. One 
commenter opposed the requirement for secondary containment on the 
grounds that impervious containment of a volume greater than the 
largest single tank may not be necessary for all tanks, and that 
existing facilities may find it difficult to retrofit. In this vein, 
another commenter asked for a phase-in of the requirements, and a third 
asked for variance provisions so that a facility would not have to make 
small additions to its secondary containment for minimum environmental 
benefit. Another commenter argued that the requirement should be 
applied to large facilities only. One commenter believed that the 
proposal duplicates NPDES stormwater rules. Two commenters believed the 
requirement should apply only to unmanned facilities. See also the 
comments and response to comments concerning secondary containment in 
the discussion of Sec. 112.7(c), above.
    Sufficient freeboard. Several commenters said that the standard of 
a 25-year storm event might be difficult to determine without extensive 
meteorological studies. Other commenters asked for clarification of the 
terms ``sufficient'' and ``freeboard,'' or of the phrase ``sufficient 
freeboard.'' Likewise, several commenters asked for clarification of 
the Agency's position that sufficient freeboard would be that which 
would withstand a 25-year storm event. Two commenters suggested a 
standard of 110% of tank capacity. Other commenters suggested 
alternatives for the 25-year storm event, such as a 24-hour, 10 year 
rain; or a 24-hour, 25-year storm. Another commenter suggested the 
adequacy of freeboard should be left flexible on a facility-specific 
basis.
    Seventy-two-hour impermeability standard. Similar to the comments 
directed toward the proposed requirements for secondary containment in 
Sec. 112.7(c), some commenters objected to the proposed 72-hour 
impermeability standard. See the comments and response to comments for 
Sec. 112.7(c) above.
    Response to comments. Secondary containment, in general. A primary 
containment system is the container or equipment in which oil is stored 
or used. Secondary containment is a requirement for all bulk storage 
facilities, large or small, manned or unmanned; and for facilities that 
use oil-filled equipment; whenever practicable. Such containment must 
at least provide for the capacity of the largest single tank with 
sufficient freeboard for precipitation. A discharge as described in 
Sec. 112.1(b) from a small facility may be as environmentally 
devastating as such a discharge from a large facility, depending on the 
surrounding environment. Likewise, a discharge from a manned facility 
needs to be contained just as a discharge from an unmanned one. A 
phase-in of these requirements is not appropriate because secondary 
containment is already required under current rules. When secondary 
containment is not practicable, the owner or operator of a facility may 
deviate from the requirement under Sec. 112.7(d), explain the rationale 
in the Plan, provide a contingency plan following the provisions of 40 
CFR part 109, and otherwise comply with Sec. 112.7(d).
    Because a pit used as a form of secondary containment may pose a 
threat to birds and wildlife, we encourage an owner or operator who 
uses a pit to take measures to mitigate the effect of the pit on birds 
and wildlife. Such measures may include netting, fences, or other means 
to keep birds or animals away. In some cases, pits may also cause a 
discharge as described in Sec. 112.1(b). The discharge may occur when 
oil spills over the top of the pit or when oil seeps through the ground 
into groundwater, and thence to navigable waters or adjoining 
shorelines. Therefore, we recommend that an owner or operator not use 
pits in an area where such pit may prove a source of such discharges. 
Should the oil reach navigable waters or adjoining shorelines, it is a 
reportable discharge under 40 CFR 110.6.
    We disagree that the rule is duplicative of NPDES rules. Forseeable 
or chronic point source discharges that are permitted under CWA section 
402, and that are either due to causes associated with the 
manufacturing or

[[Page 47117]]

other commercial activities in which the discharger is engaged or due 
to the operation of treatment facilities required by the NPDES permit, 
are to be regulated under the NPDES program. ``Classic spill'' 
situations are subject to the requirements of CWA section 311. Such 
spills are governed by section 311 even where the discharger holds a 
valid and effective NPDES permit under section 402. 52 FR 10712, 10714. 
Therefore, the typical bulk storage facility with no permitted 
discharge or treatment facility would not be under the NPDES rules.
    The secondary containment requirements of the rule apply to bulk 
storage containers and their purpose is to help prevent discharges as 
described in Sec. 112.1(b) by containing discharged oil. NPDES rules, 
on the other hand, may at times require secondary containment, but do 
not always. Furthermore, NPDES rules may not always apply to bulk 
storage facilities. Therefore, the rule is not always duplicative of 
NPDES rules. Where it is duplicative, an owner or operator of a 
facility subject to NPDES rules may use that portion of his Best 
Management Practice Plan as part of his SPCC Plan.
    Sufficient freeboard. An essential part of secondary containment is 
sufficient freeboard to contain precipitation. Whatever method you use 
to calculate the amount of freeboard that is ``sufficient'' must be 
documented in the Plan. We believe that the proper standard of 
``sufficient freeboard'' to contain precipitation is that amount 
necessary to contain precipitation from a 25-year, 24-hour storm event. 
That standard allows flexibility for varying climatic conditions. It is 
also the standard required for certain tank systems storing or treating 
hazardous waste. See, for example, 40 CFR 265.1(e)(1)(ii) and 
(e)(2)(ii). While we believe that 25-year, 24-hour storm event standard 
is appropriate for most facilities and protective of the environment, 
we are not making it a rule standard because of the difficulty and 
expense for some facilities of securing recent information concerning 
such storm events at this time. Recent data does not exist for all 
areas of the United States. Furthermore, available data may be costly 
for small operators to secure. Should recent and inexpensive 
information concerning a 25-year, 24-hour storm event for any part of 
the United States become easily accessible, we will reconsider 
proposing such a standard.
    Seventy-two-hour impermeability standard. As noted above, we have 
decided to withdraw the proposal for the 72-hour impermeability 
standard and retain the current standard that diked areas must be 
sufficiently impervious to contain oil. We take this step because we 
agree with commenters that the purpose of secondary containment is to 
contain oil from reaching waters of the United States. The rationale 
for the 72-hour standard was to allow time for the discovery and 
removal of an oil spill. We believe that an owner or operator of a 
facility should have flexibility in how to prevent discharges as 
described in Sec. 112.1(b), and that any method of containment that 
achieves that end is sufficient. Should such containment fail, an owner 
or operator must immediately clean up any discharged oil. Similarly, we 
intend that the purpose of the ``sufficiently impervious'' standard is 
to prevent discharges as described in Sec. 112.1(b) by ensuring that 
diked areas can contain oil and are sufficiently impervious to prevent 
such discharges.
    Industry standards. Industry standards that may assist an owner or 
operator with secondary containment for bulk storage containers 
include: (1) NFPA 30, ``Flammable and Combustible Liquids Code''; (2) 
BOCA, National Fire Prevention Code; (3) API Standard 2610, ``Design 
Construction, Operation, Maintenance, and Inspection of Terminal and 
Tank Facilities''; and, (4) Petroleum Equipment Institute Recommended 
Practice 200, ``Recommended Practices for Installation of Aboveground 
Storage Systems for Motor Vehicle Fueling.''
    Editorial changes and clarifications. In the first sentence, 
``spill'' becomes ``discharge.'' Also in that sentence, ``contents of 
the largest single tank'' becomes ``capacity of the largest single 
container.'' This is merely a clarification and has always been the 
intent of the rule. The contents of a container may vary from day to 
day, but the capacity remains the same. In discussing capacity, we 
noted in the 1991 preamble that ``the oil storage capacity (emphasis 
added) of the equipment, however, must be included in determining the 
total storage capacity of the facility, which determines whether a 
facility is subject to the Oil Pollution Prevention regulation.'' 56 FR 
54623. We discuss this capacity in the context of the general 
requirements for secondary containment. Thus, it is clear that we have 
always intended capacity to be the determinative factor in both 
subjecting a facility to the rule and in determining the need for 
secondary containment.
    We also deleted the phrase ``but they may not always be 
appropriate'' from the third sentence of the paragraph because it is 
confusing when compared to the text of Sec. 112.7(d). Under 
Sec. 112.7(d), if secondary containment is not practicable, you may 
provide a contingency plan in your SPCC Plan and otherwise comply with 
that section. In the last sentence, ``plant'' becomes ``facility.'' 
Also in that sentence, the phrase ``so that a spill could terminate *  
*  *'' becomes ``so that any discharge will terminate.*  *  *''

Section 112.8(c)(3)--Drainage of Rainwater

    Background. In 1991, we reproposed the current rule on drainage of 
rainwater, incorporating the CWA standard, i.e., ``that may be 
harmful,'' into the proposal.
    In 1997, we proposed that records required under NPDES 
Secs. 122.41(j)(2) and 122.41(m)(3) would suffice for purposes of this 
section, so that you would not have to prepare duplicate records 
specifically for SPCC purposes. The proposed change would also apply to 
records maintained regarding inspection of diked areas in onshore oil 
production facilities prior to drainage. See 112.9(b)(1).
    Comments. 1991 comments. One commenter in 1991 suggested that we 
allow use of NPDES records for purposes of this section. Another 
commenter suggested that records of discharges that do not violate 
water quality standards are unnecessary.
    1997 comments. Many commenters favored the 1997 proposal. One 
commenter opposed the proposal if the records were not to be required 
by NPDES. Specifically, the commenter sought an exemption for 
discharges of rainwater containing animal fats and vegetable oils if 
such discharges are not regulated under NPDES rules. The commenter 
believed that an exception should be created for reporting and 
recording dike bypasses of Sec. 112.7(e)(2)(iii)(D) relating to animal 
fats and vegetable oil storage, only requiring such reporting and 
recording if required by an NPDES stormwater permit, because in all 
cases discharge of contaminated stormwater is not permitted. Asking why 
EPA should regulate stormwater bypass events if the stormwater is not 
contaminated, the commenter argued that if stormwater permits do not 
require reporting and recording of dike bypass events, then EPA should 
not require an added tier of regulation under SPCC Plans. Other 
commenters thought that EPA was adopting by reference the NPDES rules 
and sought clarification on the issue.
    Response to comments. We agree with the first 1991 commenter 
mentioned above and proposed that change in 1997. We disagree with the 
second 1991 commenter that records of discharges

[[Page 47118]]

that do not violate water quality standards are unnecessary. Such 
records show that the facility has complied with the rule.
    We are not adopting the NPDES rules for SPCC purposes, but are only 
offering an alternative for recordkeeping. The intent of the rule is 
that you may, if you choose, use the NPDES stormwater discharge records 
in lieu of records specifically created for SPCC purposes. We are not 
incorporating the NPDES requirements into our rules by reference.
    This paragraph applies to discharges of rainwater from diked areas 
that may contain any type of oil, including animal fats and vegetable 
oils. The only purpose of this paragraph is to offer a recordkeeping 
option so that you do not have to create a duplicate set of records for 
SPCC purposes, when adequate records created for NPDES purposes already 
exist.
    Editorial changes and clarifications. In the introduction to the 
paragraph (c)(3), ``drainage of rainwater'' becomes ``drainage of 
uncontaminated rainwater.'' In paragraph (c)(3)(ii), which read, ``*  *  
* run-off rainwater ensures compliance with applicable water quality 
standards and will not cause a discharge as described in 40 CFR part 
110'' becomes ``*  *  * retained rainwater to ensure that its presence 
will not cause a discharge as described in Sec. 112.1(b).'' Also in 
that paragraph, we deleted the phrase ``applicable water quality 
standards'' because such standards are encompassed within the phrase 
``a discharge as described in Sec. 112.1(b).''

Section 112.8(c)(4)--Completely Buried Tanks; Corrosion Protection

    Background. In 1991, we reproposed the current rule requiring that 
new completely buried metallic storage tank installations (i.e., 
installed on or after January 10, 1974) must be protected from 
corrosion by coatings, cathodic protection, or effective methods 
compatible with local soil conditions. We recommended that such buried 
tanks be subjected to regular leak testing. The rationale for the 
recommendation was that testing technology was rapidly advancing and we 
wanted more information on such technology before making the 
recommendation a requirement. We also stated a desire to be consistent 
with many State rules.
    Comments. Corrosion protection. One commenter supported the 
proposal for corrosion protection. Another thought a requirement for 
corrosion protection ``if soil conditions warrant'' would be 
unenforceable. A third commenter complained that the proposal included 
no discussion of cathodic protection for tank bottoms in contact with 
soil or fill materials. Others thought facilities with underground 
tanks subject to part 112 should be required to develop a corrosion 
protection plan consistent with 40 CFR part 280, the rules for the 
Underground Storage Tanks Program.
    Leak testing. Several commenters opposed the proposed 
recommendation for leak testing, arguing that owner/operator discretion 
should be retained. One commenter suggested that practices for annual 
integrity testing and for the installation of pipes under 40 CFR part 
280 should be changed from recommended practices to required practices 
because recommendations with standards are not usually followed.
    Response to comments. Corrosion protection. We agree in principle 
that all completely buried tanks should have some type of corrosion 
protection, but as proposed, we will only extend that requirement to 
new completely buried metallic storage tanks. Because corrosion 
protection is a feature of the current rule (see Sec. 112.7(e)(2)(iv)), 
the requirement applies to completely buried metallic tanks installed 
on or after January 10, 1974. The requirement is enforceable because it 
is a procedure or method to prevent the discharge of oil. See section 
311(j)(1)(C) of the CWA. Most owners or operators of completely buried 
storage tanks will be exempted from part 112 under this rule because 
such tanks are subject to all of the technical requirements of 40 CFR 
part 280 or a State program approved under 40 CFR part 281. Those tanks 
subject to 40 CFR part 280 or a State program approved under 40 CFR 
part 281 will follow the corrosion protection provisions of that rule, 
which provides comparable environmental protection. Those that remain 
subject to the SPCC regulation must comply with this paragraph.
    The rule requires corrosion protection for completely buried 
metallic tanks by a method compatible with local soil conditions. Local 
soil conditions might include fill material. The method of such 
corrosion protection is a question of good engineering practice which 
will vary from facility to facility. You should monitor such corrosion 
protection for effectiveness, in order to be sure that the method of 
protection you choose remains protective. See Sec. 112.8(d)(1) for a 
discussion of corrosion protection for buried piping.
    Leak testing. The current SPCC rule contains a provision calling 
for the ``regular pressure testing'' of buried metallic storage tanks. 
40 CFR 112.7(e)(2)(iv). We proposed in 1991 a recommendation that such 
buried tanks be subject to regular ``leak testing.'' Proposed 
Sec. 112.8(c)(4). Leak testing for purposes of this paragraph is 
testing to ensure liquid tightness of a container and whether it may 
discharge oil. We specified leak testing in the proposal, instead of 
pressure testing, in order to be consistent with many State regulations 
and because the technology on such testing was rapidly evolving. 56 FR 
at 54623.
    We are modifying the leak testing recommendation to make it a 
requirement. We agree with the commenter who argued that such testing 
should be mandatory because recommendations may not often be followed. 
Appropriate methods of testing should be selected based on good 
engineering practice. Whatever method and schedule for testing the PE 
selects must be described in the Plan. Testing under the standards set 
out in 40 CFR part 280 or a State program approved under 40 CFR part 
281 is certainly acceptable (as we suggested in the proposed rule). 
``Regular testing'' means testing in accordance with industry standards 
or at a frequency sufficient to prevent leaks.
    Editorial changes and clarifications. The first sentence of the 
proposed rule was deleted because it was surplus, and contained no 
mandatory requirements. It merely noted that completely buried metallic 
storage tanks represent a potential for undetected spills. ``Buried 
installation'' becomes ``completely buried metallic storage tank,'' to 
accord with the definition in Sec. 112.2. We clarify that a ``new'' 
installation is one installed on or after January 10, 1974, the 
effective date of the SPCC rule, by deleting the word ``new'' and 
substituting the date. We deleted the phrase ``or other effective 
methods,'' because it is confusing when compared to the text of 
Sec. 112.7(a)(2). Under Sec. 112.7(a)(2), if you explain your reasons 
for nonconformance, you may use alternate methods providing equivalent 
environmental protection.

Section 112.8(c)(5)--Partially Buried or Bunkered Tanks; Corrosion 
Protection

    Background. In 1991, we proposed changing the current requirement 
to avoid using partially buried metallic tanks into a recommendation. 
We proposed that if you do use such tanks, that you must protect them 
from corrosion.
    Comments. One commenter argued that the rule should only apply to 
new tanks.
    Response to comments. Requirement v. recommendation. Due to the 
risk of discharge caused by corrosion, we

[[Page 47119]]

decided to keep the current requirement to not use partially buried 
metallic tanks, unless the buried section of such tanks are protected 
from corrosion. The requirement to not use such tanks, unless they are 
protected from corrosion, applies to all partially buried metallic 
tanks, installed at any time.
    Editorial changes and clarifications. Bunkered tanks are a subset 
of partially buried tanks, and are included within the rule to clarify 
that it applies to all partially buried tanks. We did not finalize the 
proposed phrase ``or other effective methods,'' because it is confusing 
when compared to the text of Sec. 112.7(a)(2). Under Sec. 112.7(a)(2), 
if you explain your reasons for nonconformance, you may use alternate 
methods providing equivalent environmental protection. The proposed 
recommendation that ``partially buried or bunkered metallic tanks be 
avoided, since partial burial at the earth can cause rapid corrosion of 
metallic surfaces, especially at the earth/air interface'' becomes a 
requirement to ``not use partially buried or bunkered metallic tanks 
for the storage of oil unless you protect the buried section of the 
tank from corrosion.''

Section 112.8(c)(6)--Integrity Testing

    Background. In 1991, we proposed that integrity testing for bulk 
storage tanks be conducted at least every ten years and when material 
repairs are conducted. We gave several examples of ``material repairs'' 
in the preamble. The current requirement for such testing is that it be 
``periodic.'' We also proposed that visual inspection, as a method of 
testing, must be combined with some other method, because visual 
testing alone is insufficient for an integrity test. 56 FR at 54623.
    In 1997, we added a proposed sentence to the rule which would allow 
the use of usual and customary business records for integrity testing. 
We suggested that records maintained under API Standards 653 and 2610 
would suffice for this purpose.
    Comments. 10-year integrity testing in general. One commenter asked 
for a clarification of the term ``integrity testing.'' Several 
commenters favored the proposal for ten-year integrity testing. Other 
commenters opposed the requirement or favored turning it into a 
recommendation. Several commenters proposed testing according to 
accepted industry standards, such as American Petroleum Institute 
(API), National Fire Protection Association (NFPA), Underwriters 
Laboratory (UL), or American Society of Mechanical Engineers (ASME).
    Applicability of integrity testing. Some asked for an exemption for 
tanks inside buildings. Others asked for an exemption for number 5 and 
6 fuel oils, and asphalt, because such oils are heavy and would not 
flow very far. Some commenters believed the requirement should not 
apply to small facilities because it is ``not standard industry 
practice'' to conduct these tests at small facilities. Another 
commenter stated that while most large corporations perform testing at 
some frequency, most smaller businesses do not. The commenter suggested 
that exemptions because of size or quantity of oil stored should not be 
granted because the smaller facilities generally are more in need of 
testing.
    Several commenters suggested that integrity testing should be 
waived for tanks which can be visually inspected on the bottom and all 
sides, such as tanks located off the ground on crates, and which have 
secondary containment. One commenter asked that the requirement apply 
only when the tank is used to store corrosive materials or where the 
tank has failed within the last five years. Other commenters asked for 
a phase-in of the requirement. Utilities asked that the requirement not 
apply to electrical equipment because no methods exist for integrity 
testing of such equipment, and because the primary reason for failure 
of such equipment is not corrosion, but mechanical failure.
    Material repairs. Several commenters asked for clarification as to 
the meaning of ``material repairs.''
    Method of testing. Some commenters favored visual inspection only 
because it might be used more frequently than any other method of 
testing. Another commenter asked for clarification if visual inspection 
meant inspection of both the interior and exterior of a tank. Another 
commenter suggested that we augment integrity testing procedures with 
procedures to test the tank bottom for settlement and corrosion, and to 
test roof supports.
    Business records. Most commenters favored the proposal to allow use 
of usual and customary business records for integrity testing and other 
purposes. Some commenters argued that the suggested API Standards were 
unfamiliar to many owners and operators.
    Response to comments. 10-year integrity testing in general. 
Integrity testing is a necessary component of any good prevention plan. 
A number of commenters supported a requirement for such testing. It 
will help to prevent discharges by testing the strength and 
imperviousness of the container. We agree with commenters that testing 
according to industry standards is preferable, and thus will maintain 
the current standard of regularly scheduled testing instead of 
prescribing a particular period for testing. Industry standards may at 
times be more specific and more stringent than our proposed rule. For 
example, API Standard 653 provides specific criteria for internal 
inspection frequencies based on the calculated corrosion rate, rather 
than an arbitrary time period. API Standard 653 allows the aboveground 
storage tank (AST) owner or operator the flexibility to implement a 
number of options to identify and prevent problems which ultimately 
lead to a loss of tank integrity. It establishes a minimum and maximum 
interval between internal inspections. It requires an internal AST 
inspection when the estimated corrosion rate indicates the bottom will 
have corroded to 0.1 inches. Certain prevention measures taken to 
prevent a discharge from the tank bottom may affect this action level 
(thickness). Once this point has been reached, the owner or operator 
has to make a decision, depending on the future service and operating 
environment of the tank, to either replace the whole tank, line the 
bottom, add cathodic protection, replace the tank bottom with a new 
bottom, add a release prevention barrier, or some combination of the 
above.
    Another benefit from the use of industry standards is that they 
specify when and where specific tests may and may not be used. For 
example, API Standard 653 is very specific as to when radiographic 
tests may be used and when a full hydrostatic test is required after 
shell repairs. Depending on shell material toughness and thickness a 
full hydrotest is required for certain shell repairs. Allowing a visual 
inspection in these cases risks a tank failure similar to the 1988 
Floreffe, Pennsylvania event. Testing on a ``regular schedule'' means 
testing per industry standards or at a frequency sufficient to prevent 
discharges. Whatever schedule the PE selects must be documented in the 
Plan.
    Applicability of integrity testing. Integrity testing is essential 
for all aboveground containers to help prevent discharges. Testing will 
show whether corrosion has reached a point where repairs or replacement 
of the container is needed. Prevention of discharges is preferable to 
cleaning them up afterwards. Therefore, it must apply to large and 
small containers, containers on and off the ground wherever located, 
and to containers storing any type of oil. From all of these containers 
there exists the possibility of discharge. Because electrical, 
operating, and manufacturing

[[Page 47120]]

equipment are not bulk storage containers, the requirement is 
inapplicable to those devices or equipment. 56 FR 54623. Also, as noted 
by commenters, methods may not exist for integrity testing of such 
devices or equipment.
    Material repairs. The rationale for testing at the time material 
repairs are conducted is that such repairs could materially increase 
the potential for oil to be discharged from the tank. Examples of such 
repairs include removing or replacing the annular plate ring; 
replacement of the container bottom; jacking of a container shell; 
installation of a 12-inch or larger nozzle in the shell; a door sheet, 
tombstone replacement in the shell, or other shell repair; or, such 
repairs that might materially change the potential for oil to be 
discharged from the container.
    Method of testing. The rule requires visual testing in conjunction 
with another method of testing, because visual testing alone is 
normally insufficient to measure the integrity of a container. Visual 
testing alone might not detect problems which could lead to container 
failure. For example, studies of the 1988 Ashland oil spill suggest 
that the tank collapse resulted from a brittle fracture in the shell of 
the tank. Adequate fracture toughness of the base metal of existing 
tanks is an important consideration in discharge prevention, especially 
in cold weather. Although no definitive non-destructive test exists for 
testing fracture toughness, had the tank been evaluated for brittle 
fracture, for example under API standard 653, and had the evaluation 
shown that the tank was at risk for brittle fracture, the owner or 
operator could have taken measures to repair or modify the tank's 
operation to prevent failure.
    For certain smaller shop-built containers in which internal 
corrosion poses minimal risk of failure; which are inspected at least 
monthly; and, for which all sides are visible (i.e., the container has 
no contact with the ground), visual inspection alone might suffice, 
subject to good engineering practice. In such case the owner or 
operator must explain in the Plan why visual integrity testing alone is 
sufficient, and provide equivalent environmental protection. 40 CFR 
112.7(a)(2). However, containers which are in contact with the ground 
must be evaluated for integrity in accordance with industry standards 
and good engineering practice.
    Business records. You may use usual and customary business records, 
at your option, for purposes of integrity testing recordkeeping. 
Specifically, you may use records maintained under API Standards 653 
and 2610 for purposes of this section, if you choose. Other usual and 
customary business records either existing or to be developed in the 
future may also suffice. Or, you may elect to keep separate records for 
SPCC purposes. This section requires you to keep comparison records. 
Section 112.7(e) requires retention of these records for three years. 
You should note, however, that certain industry standards (for example, 
API Standards 570 and 653) may specify that an owner or operator 
maintain records for longer than three years.
    Industry standards. Industry standards that may assist an owner or 
operator with integrity testing include: (1) API Standard 653, ``Tank 
Inspection, Repair, Alteration, and Reconstruction''; (2) API 
Recommended Practice 575, ``Inspection of Atmospheric and Low-Pressure 
Tanks;'' and, (3) Steel Tank Institute Standard SP001-00, ``Standard 
for Inspection of In-Service Shop Fabricated Aboveground Tanks for 
Storage of Combustible and Flammable Liquids.''
    Editorial changes and clarifications. In the first sentence, 
``Aboveground tanks shall be subject to integrity testing * * *'' 
becomes ``Test each container for integrity * * *'' Also in that 
sentence, the phrase ``or a system of non-destructive shell testing'' 
becomes ``or another system of non-destructive shell testing.'' The 
last sentence which read, ``* * * the outside of the container must be 
frequently observed by operating personnel for signs of deterioration, 
leaks, * * *'' becomes ``* * * you must frequently inspect the outside 
of the container for signs of deterioration, leaks, * * *'' We made 
that change because the requirements of this paragraph are the 
responsibility of the owner or operator, not of ``operating 
personnel.''
    ``Integrity testing'' is any means to measure the strength 
(structural soundness) of the container shell, bottom, and/or floor to 
contain oil and may include leak testing to determine whether the 
container will discharge oil. It includes, but is not limited to, 
testing foundations and supports of containers. Its scope includes both 
the inside and outside of the container. It also includes frequent 
observation of the outside of the container for signs of deterioration, 
leaks, or accumulation of oil inside diked areas.

Section 112.8(c)(7)--Leakage; Internal Heating Coils

    Background. In 1991, we proposed that the current rule on 
controlling leakage through defective internal heating coils should be 
modified to include a recommendation that retention systems be designed 
to hold the contents of an entire tank. We also proposed to change the 
current requirement to consider the feasibility of installing external 
heating systems into a recommendation.
    Comments. One commenter proposed that instead of requiring a 
retention system which would hold the entire contents of a tank, that 
an oil/water separator might work just as well. Another commenter 
opposed requiring the use of oil/water separators. As to the proposed 
recommendation to consider use of external heating systems, one 
commenter objected to the cost which might be incurred. One commenter 
opposed the proposed recommendation due to the belief that leaks in the 
aboveground piping can be mitigated through daily inspections and they 
are often placed within secondary containment. Another commenter 
asserted that with drainage routed to oil/water separators or holding 
ponds, leak proof galleys under aboveground piping were redundant and 
economically unjustified.
    Response to comments. The rule does not mandate the use of any 
specific separation or retention system. Any system that achieves the 
purpose of the rule is acceptable. That purpose is to prevent 
discharges as described in Sec. 112.1(b) by controlling leakage.
    Editorial changes and clarifications. We deleted the proposed 
recommendations from the rule because we do not wish to confuse the 
regulated public as to what is mandatory and what is discretionary. We 
have included only requirements in the rule.

Section 112.8(c)(8)--Good Engineering Practice--Alarm Systems

    Background. In 1991, we reproposed the current rule on ``fail-
safe'' engineering. We added a proposal to allow alternate 
technologies. We recommended that sensing devices be tested in 
accordance with industry standards.
    Comments. Editorial changes and clarifications. Several commenters 
objected to the term ``fail-safe'' engineering because they believe 
that nothing is ever fail-safe. They suggested using the term ``in 
accordance with good engineering practice,'' or ``consistent with 
accepted industry practices'' instead.
    Applicability. One commenter thought the proposed requirement 
should apply to large facilities only or facilities that were the cause 
of a reportable spill within the preceding three years. One commenter 
suggested a phase-in of the requirement.

[[Page 47121]]

    Monitoring. One commenter suggested that a person must be present 
to monitor gauges when a fast response system is used to prevent 
container overfilling. Another suggested that the requirement for alarm 
devices not apply to containers where an operator is present.
    Alternatives. One commenter suggested that certain ``procedures'' 
might suffice instead of alarm devices. Another commenter suggested 
that we need to be specific as to methods of testing.
    Response to comments. Applicability. Alarm system devices are 
necessary for all facilities, large or small, to prevent discharges. 
Such systems alert the owner or operator to potential container 
overfills, which are a common cause of discharges. Because this is a 
requirement in the current rule, no phase-in is necessary.
    Monitoring. We agree with the commenter that a person must be 
present to monitor a fast response system to prevent overfills and have 
amended the rule accordingly. We disagree that the requirement for 
alarm devices should not apply when a person is present, because human 
error, negligence, on inattention may still occur in those cases, 
necessitating some kind of alarm device.
    Alternatives. Under the deviation rule at Sec. 112.7(a)(2), you may 
substitute ``procedures'' or other measures that provide equivalent 
environmental protection as any of the alarm systems mandated in the 
rule if you can explain your reasons for nonconformance.
    Industry standards. Industry standards that may assist an owner or 
operator with alarm systems, discharge prevention systems, and 
inventory control include: (1) NFPA 30, ``Flammable and Combustible 
Liquids Code''; (2) API Recommended Practice 2350, ``Overfill 
Protection for Storage Tanks in Petroleum Facilities''; and, (3) API, 
``Manual of Petroleum Measurement Standards.''
    Editorial changes and clarifications. Throughout, ``tank'' becomes 
``container.'' In the introductory paragraph, we deleted the words ``as 
far as practical'' from the rule text because they are confusing when 
compared with the text of Sec. 112.7(a)(2). Under Sec. 112.7(a)(2), you 
may deviate from a requirement if you explain your reasons for 
nonconformance and provide equivalent environmental protection. 
``Spills'' becomes ``discharges.'' We agree with the commenter that 
``fail-safe'' engineering is inappropriate and have substituted ``in 
accordance with good engineering practice.'' The change in terminology 
does not imply any substantive change in the level of environmental 
protection required, it is merely editorial. Finally, in the 
introductory paragraph the phrase ``one or more of the following 
devices'' becomes ``at least one of the following.'' Not all of the 
items listed under this paragraph are devices. For example, regular 
testing of liquid sensing devices is a procedure. Therefore, the word 
``devices'' was incomplete. In paragraph (i), ``manned operation'' 
becomes ``attended operation,'' and ``plants'' becomes ``facilities.'' 
In paragraph (iv), the phrase ``or their equivalent,'' was deleted 
because it is confusing when compared with the text of 
Sec. 112.7(a)(2). Under Sec. 112.7(a)(2), you may deviate from a 
requirement if you explain your reasons for nonconformance, and provide 
equivalent environmental protection. Proposed paragraph (v), relating 
to alternative technologies, was deleted because alternative devices 
are allowed under Sec. 112.7(a)(2).

Section 112.8(c)(9)--Effluent Disposal Facilities

    Background. In 1991, we reproposed the current rule on observation 
of effluent disposal facilities.
    Comments. We received only one comment which asked us to clarify 
that ``effluents'' mean oil-contaminated water collected within 
secondary containment areas, and that ``disposal facilities'' means 
``treatment facilities.''
    Editorial changes and clarifications. ``Oil spill event'' becomes 
``discharge as described in Sec. 112.1(b).'' ``System upset'' refers to 
an event involving a discharge of oil-contaminated water. ``Effluent'' 
means oil-contaminated water. ``Disposal facilities'' becomes 
``effluent treatment facilities.''

Section 112.8(c)(10)--Visible Oil Leaks

    Background. In 1991, we reproposed the current requirement that 
visible oil leaks must be promptly corrected. Additionally, we proposed 
that accumulated oil or oil-contaminated materials must be removed 
within 72 hours. The 72-hour proposal in this paragraph was consistent 
with the proposal in Sec. 112.7(c). The rationale was that a 72-hour 
time period would allow time for discovery and removal of an oil 
discharge in most cases. We suggested in the preamble to the 1991 
proposal that most facilities are attended at some time within a 72-
hour time period. 56 FR 54621.
    Comments. Editorial changes and clarifications. One commenter asked 
for clarification of the meaning of ``accumulation'' of oil. Others 
asked for clarification of the meaning of ``oil contaminated 
materials.'' Another commenter noted that reference to a spill event 
within a diked area is inconsistent with its definition.
    Applicability. Some commenters thought the requirement should not 
apply to small facilities because of the likelihood that the discharge 
would be smaller.
    Extent and methods of cleanup. One commenter suggested that 
covering soil with plastic film may be an acceptable method to prevent 
stormwater contamination during remediation. Some commenters suggested 
that where a spill creates a risk of fire or explosion, the first 
priority should be to eliminate such threats before undertaking 
cleanup. Several commenters asked whether removal of accumulations of 
oil means complete removal. Some commenters feared that a requirement 
to remove oil-contaminated materials would be interpreted to mean that 
cleanup of portions of the dike that are oil-stained is required. The 
commenters were concerned that such a cleanup would undermine the 
stability of the dike and would be unnecessary. One commenter argued 
that complete removal would compound landfill disposal problems. 
Another commenter asked whether the rule contemplates cleanup of soil 
contaminated by past practices. Some commenters argued that the 72-hour 
requirement would preclude bioremediation.
    72-hour cleanup standard. Some commenters asked how a 72-hour time 
limit would be calculated. Those commenters suggested that the clock 
begin to run from the time of the discharge itself, or of its 
discovery. Others suggested different time periods from 
``immediately,'' ``as soon as possible,'' ``within 72 hours,'' ``within 
96 hours,'' or ``expeditiously.'' One commenter suggested no time 
limit. Some commenters noted that a containment system might be 
designed to contain oil for more than 72 hours before it begins to 
leak.
    One commenter suggested that, depending on site conditions, a 72-
hour time limit might jeopardize worker health and safety. Another 
sought clarification on the need to clean up small discharges as 
opposed to larger ones within the proposed time limit.
    Numerous commenters opposed this requirement because it might 
preclude bioremediation. Some thought it would be impossible to meet.
    Response to comments. Applicability. The requirement to clean up an 
accumulation of oil is applicable to all facilities, large and small. 
The damage to the environment may be the same, depending on the amount 
discharged.

[[Page 47122]]

    Extent of and methods of cleanup. Prevention of contamination is 
always the preferred alternative. If you choose, you may spread plastic 
film over the diked area if it will prevent the occurrence of an 
accumulation of oil. Of course, you must then dispose of the film 
properly. We agree with commenters that where a discharge creates a 
risk of fire or explosion, the first priority should be to eliminate 
such threat before undertaking cleanup. But once that threat is 
removed, correction of the source of the discharge and cleanup must 
begin promptly.
    No matter what method of cleanup you choose, you must completely 
remove the accumulation of oil. Any method that works and complies with 
all other applicable laws and regulations is acceptable. Bioremediation 
may be one acceptable method of cleanup. Acceptable methods will depend 
on weather and other environmental conditions. We do not mean to limit 
cleanup methods, which will depend on good engineering practice. If the 
cleanup method you choose would undermine the stability of the dike, 
you must repair the dike to its previous condition.
    72-hour cleanup standard. We have deleted the 72-hour cleanup 
standard because it would preclude bioremediation. We also agree that 
under certain circumstances, such a limit might jeopardize worker 
health and safety. Therefore, we have maintained the current standard 
that visible discharges must be promptly removed. ``Prompt'' removal 
means beginning the cleanup of any accumulation of oil immediately 
after discovery of the discharge, or immediately after any actions to 
prevent fire or explosion or other threats to worker health and safety, 
but such actions may not be used to unreasonably delay such efforts. 
The size of the accumulation is irrelevant, as any accumulation may 
migrate to navigable waters or adjoining shorelines.
    Editorial changes and clarifications. ``Leaks'' becomes 
``discharges.'' ``Tank'' becomes ``container.'' ``Accumulation of oil'' 
means a discharge that causes a ``film or sheen'' in a diked area, or 
causes a sludge or emulsion there. See 40 CFR 110.3(b). The reference 
to violation of applicable water quality standards in 40 CFR 110.3(b) 
does not apply here because the rule assumes that the oil will not have 
reached any waters of the United States or adjoining shorelines, but 
stays entirely within the diked area of the facility. The term ``oil-
contaminated materials'' is not used in the rule. We eliminate the term 
``oil-contaminated materials'' that was used in the proposed rule 
because oil must accumulate on something such as materials or soil. 
Therefore, the term is redundant. Instead we refer to an accumulation 
of oil, which includes anything on which the oil gathers or amasses 
within the diked area. Such accumulation may include oil-contaminated 
soil or any other oil-contaminated material within the diked area 
impairing the secondary containment system. See also the discussion of 
``accumulation of oil'' included with the response to comments of 
Sec. 112.9(b)(2). We have removed the term ``spill event'' from the 
proposed paragraph and note that we agree with the commenter who noted 
that reference to a ``spill event,'' or ``a discharge as described in 
Sec. 112.1(b),'' within a diked area is inconsistent with that concept.

Section 112.8(c)(11)--Mobile Containers

    Background. In 1991, we proposed to require that mobile tanks be 
positioned or located to prevent oil discharges. We recommended 
secondary containment for the largest single compartment or tank of any 
mobile container. We also recommended that these containers not be 
located where they will be subject to periodic flooding or washout.
    Comments. Scope of discharge prevention. One commenter asked that 
the rule be amended to refer to discharges to navigable waters, instead 
of discharges.
    Time limits. One commenter asked that a mobile or portable 
container be defined as a container which is in place on a contiguous 
property for 10 days or less.
    Secondary containment. Two commenters supported the secondary 
containment proposals, but favored making them requirements instead of 
recommendations. One commenter asked that the secondary containment 
recommendation for the largest single compartment or container be 
modified to include tanks which are manifolded together or otherwise 
have overflow capabilities. Another commenter suggested that secondary 
containment provide freeboard sufficient to contain precipitation from 
a 25-year storm event.
    Floods. Other commenters asked for a requirement that mobile tanks 
not be located in areas subject to flooding.
    Response to comments. Scope of discharge prevention. We agree that 
the purpose of the rule is to prevent discharges from becoming 
discharges as described in Sec. 112.1(b). Therefore, in response to 
comment, we have modified the proposed rule to require positioning or 
locating mobile or portable containers to prevent ``a discharge as 
described in Sec. 112.1(b),'' rather than ``oil discharges.'' ``A 
discharge as described in Sec. 112.1(b)'' is a more inclusive term, 
tracking the expanded scope of the amended CWA.
    Time limits. We decline to place a time limitation in a definition 
of mobile or portable containers. Mobile or portable containers may be 
in place for more than ten days and still be mobile. Mobile containers 
that are in place for less than 10 days may still experience a 
discharge as described in Sec. 112.1(b).
    Secondary containment. In response to comments, we have maintained 
the secondary containment requirement in the current rule because 
secondary containment is necessary for mobile containers for the same 
reason that it is necessary for fixed containers; to prevent discharges 
from becoming discharges as described in Sec. 112.1(b). Secondary 
containment must also be designed so that there is ample freeboard for 
anticipated precipitation. We have therefore amended the rule on the 
suggestion of a commenter to provide for freeboard. We agree with the 
commenter that the amount of freeboard should be sufficient to contain 
a 25-year storm event, but are not adopting that standard because of 
the difficulty and expense for some facilities in securing recent 
information concerning 25-year, 24-hour storm events at this time. 
Should that situation change, we will reconsider proposing such a 
standard in rule text. Freeboard sufficient to contain precipitation is 
freeboard according to industry standards, or in an amount that will 
avert a discharge as described in Sec. 112.1(b). Should secondary 
containment not be practicable, you may be able to deviate from the 
requirement under Sec. 112.7(d).
    We clarify that the secondary containment requirement relates to 
the capacity of the largest single compartment or container. 
Permanently manifolded tanks are tanks that are designed, installed, or 
operated in such a manner that the multiple containers function as a 
single storage unit. Containers that are permanently manifolded 
together may count as the ``largest single compartment,'' as referenced 
in the rule.
    Floods. We deleted the proposed recommendation on siting of mobile 
containers in this rule because we do not wish to confuse the regulated 
public over what is mandatory and what is discretionary. These rules 
contain only mandatory requirements.
    Industry standards. Industry standards that may assist an owner or 
operator with secondary containment for mobile containers include: (1) 
NFPA 30, ``Flammable and Combustible

[[Page 47123]]

Liquids Code'; and, (2) BOCA, ``National Fire Prevention Code.''
    Editorial changes and clarifications. ``Spill event'' becomes ``a 
discharge as described in Sec. 112.1(b).'' ``Tank'' becomes 
``container.'' We deleted the word ``onshore'' because the whole 
section applies only to onshore facilities.

Section 112.8(d)(1)--Buried Piping--Facility Transfer Operations, 
Pumping, and Facility Process (Onshore) (Excluding Production 
Facilities)

    Background. In 1991, we proposed a new recommendation that all 
piping installations should be placed aboveground wherever possible. We 
added a new proposed requirement that would require protective coating 
and cathodic protection for new or replaced buried piping. The current 
rule requires such coating and cathodic protection only if soil 
conditions warrant. We explained in the preamble that we believe that 
all soil conditions warrant protection of buried piping. We did not 
propose to make the requirement applicable to all existing piping 
because of the significant possibility that replacing all unprotected 
buried piping might cause more discharges than it would prevent. If 
soil conditions warrant such protection for existing piping, it is 
already required by the current rule. We also proposed a new 
recommendation that buried piping installation comply to the extent 
possible with all the relevant provisions of 40 CFR part 280.
    Comments. Aboveground piping recommendation. Two commenters favored 
the recommendation. Others requested that it be modified to have all 
piping be aboveground only when appropriate, on the theory that some 
aboveground piping may become an obstacle to motorized traffic within a 
facility, or may be a hazard to worker safety because of the 
possibility of tripping over it.
    Corrosion protection. Several commenters supported the proposal to 
require corrosion protection for all new or replaced buried piping. One 
commenter believed that corrosion protection should be required, as in 
the current rule, only where soil conditions warrant. One commenter 
asked for clarification that the requirement for replaced piping only 
applies to the section replaced, not necessarily to the entire line of 
piping. Another commenter believed that corrosion protection was 
inadequate to protect from discharges, and urged a requirement for 
double-walled piping or secondary containment and product sensitive 
leak detection for new facilities. One commenter believed that the 
recommendation for buried piping installation to comply with 40 CFR 
part 280 should be a requirement, not a recommendation.
    Response to comments. Aboveground piping recommendation. While we 
have deleted the proposed recommendation from the rule text because we 
do not wish to confuse the regulated public over what is mandatory and 
what is discretionary, we still believe that piping should be placed 
aboveground whenever possible because such placement makes it easier to 
detect discharges. The decision to place piping aboveground might 
include consideration of safety and traffic factors.
    Corrosion protection. Based on EPA experience, we believe that all 
soil conditions warrant protection of new and replaced buried piping. 
EPA's cause of release study indicates that the operational piping 
portion of an underground storage tank system is twice as likely as the 
tank portion to be the source of a discharge. Piping failures are 
caused equally by poor workmanship and corrosion. Metal areas made 
active by threading have a high propensity to corrode if not coated and 
cathodically protected. See 53 FR 37082, 37127, September 23, 1988; and 
``Causes of Release from US Systems,'' September 1987, EPA 510-R-92-
702. If you decide to deviate from the requirement, for example, to 
provide an alternate means of protection other than coating or cathodic 
protection, you may do so, but must explain your reasons for 
nonconformance, and demonstrate that you are providing equivalent 
environmental protection. A deviation which seeks to avoid coating or 
cathodic protection, or some alternate means of buried piping 
protection, on the grounds that the soil is somehow incompatible with 
such measure(s), will not be acceptable to EPA.
    A ``new'' or ``replaced'' buried piping installation is one that is 
installed 30 days or more after the date of publication of this rule in 
the Federal Register. We have deleted the words ``new'' and 
``replaced'' from the proposed language and substituted this specific 
date so the effective date is clearer to the regulated community. Under 
the current rule, you have an obligation to provide buried piping 
installations with protective wrapping and coating only if soil 
conditions warrant such measures. Under the revised rule, you must 
provide such wrapping and coating for new or replaced buried piping 
installations regardless of soil conditions.
    You should consult a corrosion professional before design, 
installation, or repair of any corrosion protection system. Any 
corrosion protection you provide should be installed according to 
relevant industry standards. When piping is replaced, you must protect 
from corrosion only the replaced section, although protection of the 
entire line whenever possible is preferable. Equipping only a small 
portion of piping with corrosion protection may accelerate corrosion 
rates on connected unprotected piping. While we agree that corrosion 
protection might not prevent all discharges from buried piping, it is 
an important measure because it will help to prevent most discharges.
    Double-walled piping or secondary containment or sensitive leak 
detection for buried piping may be acceptable as a deviation from the 
requirements of this paragraph under Sec. 112.7(a)(2) if you explain 
your reasons for nonconformance with the requirement and show that the 
means you selected provides equivalent environmental protection to the 
requirement. However, we will not require such measures because we did 
not propose them.
    We have deleted the recommendation from the proposed rule that all 
buried piping installations comply to the extent practicable with 40 
CFR part 280, because we are excluding recommendations from this rule 
to avoid confusion with what is mandatory and what is discretionary. 
Also, some buried piping now subject to part 112 will be subject only 
to 40 CFR part 280 or a State program approved under 40 CFR part 281 
under this rule. See Sec. 112.1(d)(4).
    Industry standards. Industry standards that may assist an owner or 
operator with corrosion protection for buried piping installations 
include: (1) National Association of Corrosion Engineers (NACE) 
Recommended Practice-0169, ``Control of External Corrosion on 
Underground or Submerged Metallic Piping Systems''; and, (2) STI 
Recommended Practice 892, ``Recommended Practice for Corrosion 
Protection of Underground Piping Networks Associated with Liquid 
Storage and Dispensing Systems.''
    Editorial changes and clarifications. In the second sentence of 
paragraph (d)(1), we included a reference to ``a State program approved 
under part 281 of this chapter.'' In the third sentence, ``examine'' 
and ``examination'' become ``inspect'' and ``inspection.''

[[Page 47124]]

Section 112.8(d)(2)--Terminal Connections

    Background. In 1991, we proposed that when piping is not in service 
or is in standby service for 6 months or more, the terminal connection 
at the transfer point must be capped or blank-flanged and marked as to 
origin. The current rule requires such capping or blank-flanging when 
the piping is not in service or is in standby service ``for an extended 
time.''
    Comments. One commenter supported the six-month clarification of an 
``extended time.'' Several commenters opposed the requirement to cap or 
blank-flange piping in standby service because such piping may be 
needed to be put into service quickly during an emergency to ensure 
safe operations at the facility. The commenter suggested that the rule 
be reworded to say ``When piping is not in service or is not in standby 
service.''
    Response to comments. We have decided to keep the current standard 
of requiring capping or blank-flanging terminal connections when such 
piping is not in service or is in standby for an extended time in order 
to maintain flexibility for variable facilities and engineering 
conditions. We define ``an extended time'' in reference to industry 
standards or at a frequency sufficient to prevent discharges. We 
disagree with commenters that the requirement should not apply to 
piping that is not in standby service because some discharges may be 
caused by loading or unloading oil through the wrong piping or turning 
the wrong valve when the piping in question was actually out-of-
service. Typically, piping that is in standby service is only needed in 
emergency situations or when there is an operational problem. In the 
rare situations when such piping is needed immediately, the owner or 
operator may remove the cap or blank-flange to return the piping to 
service.
    Editorial changes and clarifications. ``Examine'' becomes 
``inspect.''

Section 112.8(d)(3)--Pipe Supports

    Background. In 1991, we reproposed without substantive change the 
current rule concerning pipe supports.
    Comments. We received no comments on this proposal. Therefore, we 
have promulgated the provision as proposed.

Section 112.8(d)(4)--Inspection of Aboveground Valves and Piping

    Background. In 1991, we proposed that you examine all aboveground 
valves, piping, and appurtenances on at least a monthly basis. This 
contrasts with the current requirement of ``regular'' examinations. We 
also recommended that you conduct annual integrity and leak testing of 
buried piping, or that you monitor it on a monthly basis. Finally, we 
recommended that all valves, pipes, and appurtenances conform to 
relevant industry codes, such as ASME standards. We proposed deletion 
from the rule of the current requirement for periodic pressure testing 
for piping where facility drainage is such that a failure might lead to 
a spill event.
    Comments. Monthly examination of aboveground valves, piping, and 
appurtenances. One commenter supported the visual monthly examination 
proposal, but suggested that we require a more sophisticated method of 
testing every three to four years, such as pressure testing. Most other 
commenters opposed monthly examinations, on grounds of impracticality. 
Most opposing commenters urged testing on a quarterly or semiannual 
basis, or per industry standards. Some thought the requirement should 
be a recommendation, both for large and small facilities. Electrical 
utility commenters asserted that the monthly testing of millions of 
pieces of equipment would be extremely burdensome. Several commenters 
urged that the examination requirement be limited to visual examination 
because of the cost of other methods.
    Buried piping. Several commenters favored the proposed 
recommendation for annual integrity and leak testing of buried piping 
or monitoring of such piping on a monthly basis. One commenter was 
concerned that the recommendation made no concession for piping 
construction material, length of time in the ground, etc. Several 
commenters believed that the recommendation should be a requirement 
because piping often runs outside of secondary containment; buried 
piping cannot be inspected visually; discharges are common from this 
piping; and few owners or operators conduct integrity or leak testing 
of such piping. Some thought it should be a requirement for all 
facilities, others just for large facilities. One commenter thought 
that the requirement to inspect buried piping only when exposed is 
inadequate. The commenter suggested that the piping should be subject 
to pressure testing. The frequency of the testing would be based on 
aquifer use.
    Opposing commenters believed annual testing or monthly monitoring 
was unnecessary, generally citing cost and practicability reasons. Some 
suggested differing time periods for testing, such as every three 
years, or every ten years. One commenter believed that the 
recommendation should not apply to piping of less than ten feet. Others 
asked for clarification as to the type of testing contemplated. One 
commenter suggested that the recommendation be clarified to refer only 
to oil-handling piping and equipment, and not include buried piping 
unrelated to oil operations. Several commenters suggested that we add a 
requirement to the rule to conduct integrity and leak testing of 
protected piping at the time of installation, modification, 
construction, relocation, or replacement, and to conduct an engineering 
evaluation of in-service unprotected underground piping every five 
years. Another commenter suggested double-walled piping as an 
alternative. One commenter suggested that the recommendation was 
inappropriate for vaulted tanks because of the configuration of the 
tanks.
    Response to comments. Monthly inspection of aboveground valves, 
piping, and appurtenances. Inspection of aboveground valves, piping, 
and appurtenances must be a requirement to help prevent discharges. 
Such valves, piping, and appurtenances often are located outside of 
secondary containment systems, and often do not have double-wall 
protection or some form of secondary containment themselves. Therefore, 
any discharge from such valves, piping, and appurtenances is more 
likely to become a discharge as described in Sec. 112.1(b). Examination 
of discharge reports from the Emergency Response Notification System 
(ERNS) shows that discharges from such valves, piping, and 
appurtenances are much more common than catastrophic tank failure or 
discharges from tanks. The requirement must be applicable to large and 
small facilities covered by this section that store oil, because of the 
same threat of discharge.
    The requirements of this paragraph do not apply to electrical 
utilities and other facilities with oil-filled equipment because they 
are not bulk storage facilities.
    The final rule maintains the current standard of ``regular'' 
inspections, on the suggestion of commenters who noted that at some 
remote sites monthly inspections are impractical, especially in harsh 
weather conditions. Furthermore, we agree with commenters that 
``regular'' inspections are inspections conducted ``in accordance with 
accepted industry standards,'' rather than the monthly proposed 
standard. You must include appurtenances in the inspection. Inspections 
may be either visual or by

[[Page 47125]]

other means, including pressure testing. However, we do not require 
pressure testing or any other specific method. We agree that, subject 
to good engineering practice, pressure testing every three or four 
years may be warranted in addition to regular inspection of aboveground 
valves, piping, and appurtenances. However, we believe that regular 
inspection is sufficient to help prevent discharges and will not impose 
any additional requirements at this time.
    Buried piping. We have deleted the text of the proposed 
recommendation to conduct annual integrity and leak testing of buried 
piping or monitor buried piping on a monthly basis from the rule 
because we do not wish to confuse the regulated public over what is 
mandatory and what is discretionary. This rule contains only mandatory 
requirements. However, we continue to endorse the recommendation as a 
discretionary action, and suggest that you conduct such testing 
according to industry standards.
    We agree with a commenter that the proposed recommendation would 
apply only to ``oil-handling'' piping and valves, not all such piping 
and valves, which may be unrelated to oil activities. However, no 
change in rule text is necessary because the entire rule applies only 
to procedures, methods, or equipment that are involved with the storage 
or use of oil. In response to the commenter who urged that the proposed 
recommendation not apply to buried piping of less than 10 feet in 
length, we believe that any buried piping, regardless of length, may 
cause a discharge, and therefore should be tested. Double-walled piping 
might be an acceptable alternative to integrity and leak testing or 
monthly monitoring. If you choose double-walled piping as an 
alternative, you must explain your nonconformance with the rule 
requirements, and explain how double-walled piping provides equivalent 
environmental protection. See 112.7(a)(2).
    On the suggestion of commenters, we have modified the proposed 
recommendation for annual testing or monthly monitoring of buried 
piping into a requirement that you must only conduct integrity and leak 
testing of such piping at the time of installation, modification, 
construction, relocation, or replacement. We believe that when piping 
is exposed for any reason, integrity and leak testing of such exposed 
piping according to industry standards is appropriate because piping is 
visible at that point, and testing is easier because the piping is more 
accessible. The same commenters also recommended that unprotected 
underground piping be subject to engineering evaluations every five 
years, but we recommend such evaluations be conducted in accordance 
with industry standards to preserve flexibility in case the time frame 
changes with changing technology.
    If you have vaulted containers, the requirement for integrity and 
leak testing of buried piping might be the subject of a deviation under 
Sec. 112.7(a)(2) if those pipes, valves, and fittings come out of the 
top of the container and are not buried, or are encased in a double-
walled piping system and you thereby significantly reduce the potential 
for corrosion.
    Likewise, we have deleted from rule text the recommendation that 
all valves, pipes, and appurtenances conform to industry standards, but 
we endorse its substance.
    Industry standards. Industry standards that may assist an owner or 
operator with inspection and testing of valves, piping, and 
appurtenances include: (1) API Standard 570, ``Piping Inspection Code 
(Inspection, Repair, Alteration, and Rerating of In-Service Piping 
Systems''; (2) API Recommended Practice 574, ``Inspection Practices for 
Piping System Components''; (3) American Society of Mechanical 
Engineers (ASME) B31.3, ``Process Piping''; and, (4) ASME B31.4, 
``Liquid Transportation Systems for Hydrocarbons, Liquid Petroleum Gas, 
Anhydrous Ammonia, and Alcohols.''
    Editorial changes and clarifications. ``Examine'' and 
``examination'' become ``inspect'' and ``inspection.'' We have deleted 
the reference to ``operating personnel'' in the first sentence because 
all of the requirements of this rule, except when specifically noted 
otherwise, are the responsibility of the owner or operator.

Section 112.8(d)(5)--Vehicular Traffic

    Background. In 1991, we reproposed the current rule concerning 
warnings to vehicular traffic, because of vehicle size, to avoid 
endangering aboveground piping. We proposed to amend the rule to 
include avoidance of endangering ``other transfer operations'' within 
the scope of the warning. We added a recommendation that weight 
restrictions should be posted, as applicable, to prevent damage to 
underground piping.
    Comments. Vehicular warnings. Several commenters supported the 
current requirement to warn vehicular traffic to avoid endangering 
aboveground piping or other transfer operations because of vehicle 
size. Others believed that any size or weight restrictions would 
unnecessarily burden facility operations. See the comments below on 
weight restrictions. Some believed the proposed requirement should be a 
recommendation based on good engineering practices. One thought it made 
no difference. One commenter proposed as an alternative, marking such 
piping so it could be temporarily protected or avoided. One commenter 
suggested that it would be more prudent to require signs where piping 
is lower than 14 feet and located such that vehicles can traverse, and 
recommended that, in addition to signs, verbal warnings be provided.
    Weight restriction posting. Several commenters supported making 
this recommendation a requirement because good engineering practice 
will exclude heavy equipment from crossing buried piping which does not 
have adequate cover to protect the pipe.
    Others opposed it on the grounds it would restrict access to 
vehicles which ``have driven over the same piping for a dozen or more 
years.'' One commenter thought the recommendation was unnecessary 
because local building codes or other standards already address the 
issue of buried piping protection. Some thought the recommendation 
should be a matter of PE discretion. Several commenters thought that 
the recommendation should apply to large facilities only because only 
large facilities will have the type of tanker trucks on site which 
would potentially damage underground piping. One commenter thought that 
small facilities should be exempt from the recommendation.
    Another commenter believed that the recommendation should be 
restricted to situations where it is not certain that the underground 
piping can withstand all anticipated vehicular traffic. Another 
commenter suggested that if buried piping is placed across a 
thoroughfare, it should be installed with additional structural 
protection. The commenter asserted that proper installation is a 
preventative and is a better alternative than a sign because signs are 
not always heeded.
    One commenter suggested that posting of weight restrictions at 
airports in open areas would be impractical and impact operations. The 
commenter argued that the proposal was unreasonable where some buried 
piping/hydrant systems run under ramp surfaces. A railroad commenter 
argued that the recommendation is overly broad because railroads have a 
large amount of piping under track that is built to withstand maximum 
loads from vehicular traffic, making the posting of signs unnecessary 
and costly. One commenter argued that the requirement was inapplicable 
to vaulted tanks

[[Page 47126]]

because the concrete vault reduced the risk of vehicular damage.
    Response to comments. Vehicular warnings. The requirement to warn 
vehicular traffic so that no vehicle will endanger aboveground piping 
or other oil transfer operations applies to all facilities, large or 
small, because vehicular traffic may endanger aboveground piping or 
other transfer operations at all facilities. Warnings may include 
verbal warnings, signs, or marking and temporary protection of piping 
or equipment. No particular height restriction is incorporated into the 
rule. Rather, aboveground piping at any height must be protected from 
vehicular traffic unless the piping is so high that all vehicular 
traffic passes underneath the piping. In this case, or where the 
requirement is infeasible, you may be able to use the deviation 
provision in Sec. 112.7(a)(2) if you explain your reasons for 
nonconformance and provide equivalent environmental protection. We have 
deleted the clause concerning the size of vehicles that may endanger 
piping or oil transfer operations because the owner or operator may not 
be able to determine precisely when the size or weight of a vehicle 
would cause such endangerment.
    In response to commenters who suggested that the posting of signs 
is impractical and might impact operations, or would be very costly, we 
note that you may deviate from the requirement under Sec. 112.7(a)(2) 
if you explain your reasons for nonconformance and provide equivalent 
environmental protection.
    Weight restriction posting. We deleted the proposed recommendation 
concerning weight restrictions as they relate to underground piping 
from rule text, but still support it when appropriate. We include only 
mandatory items in this rule because we do not wish to confuse the 
regulated public as to what is mandatory and what is discretionary. We 
decline to make the recommendation a requirement because we believe the 
appropriate posting of weight restrictions should be a matter of good 
engineering practice.
    Editorial changes and clarifications. We deleted the references to 
verbal warning or appropriate signs in the rule. Instead, the rule 
contains an obligation to warn entering vehicular traffic. Warnings may 
be verbal, by signs, or by other appropriate methods.

Introduction to Section 112.9

    Background. We have added an introduction to help rewrite the 
section in the active voice. Since the owner or operator is the person 
with responsibility to implement a Plan, the mandates of the rule are 
properly addressed to him, except as specifically noted.

Section 112.9(a)--General Requirements--Onshore Oil Production 
Facilities

    Background. This is a new provision that merely references the 
general requirements which all facilities must meet as well as the 
specific requirements that you must meet if you are an owner or 
operator of a facility in the category of onshore oil production 
facilities.
    Editorial changes and clarifications. The obligation to ``address'' 
general SPCC requirements becomes the obligation to ``meet'' those 
requirements. ``Spill prevention'' becomes ``discharge prevention.'' We 
also deleted the word ``onshore'' from the titles of the paragraphs of 
this section because the entire section applies only to onshore 
production facilities.

Proposed Section 112.9(b)--Definition--Onshore Oil Production 
Facilities

    Background. This proposed section was merely a reference to the old 
definition of onshore oil production facility (see current 
Sec. 112.7(e)(5)(i)), which is today incorporated within the new 
definition of production facility. Therefore, the section is no longer 
necessary and we have deleted it.

Section 112.9(b)(1), Proposed as Sec. 112.9(c)(1)--Dike Drains and 
Drainage

    Background. In 1991, we reproposed the current rule concerning 
drainage of diked areas.
    Comments. Editorial changes and clarifications. One commenter 
suggested an editorial change from discharges to ``navigable waters,'' 
to a discharge as referenced in Sec. 112.1(b)(1).
    Applicability. Another commenter urged a small facility exemption 
from this requirement because the recordkeeping involved was too 
burdensome.
    Engineering methods. One commenter believed that the requirement to 
have all drains closed on dikes around storage containers might 
preclude engineering methods designed to handle flow-through conditions 
at water flood oil production operations, where large volumes of water 
may be directed to oil storage tanks if water discharge lines on oil-
water separators become plugged.
    Response to comments. Applicability. We believe that this 
requirement must be applicable to both large and small facilities to 
help prevent discharges as described in Sec. 112.1(b). The risk of such 
a discharge and the accompanying environmental damage may be 
devastating whether it comes from a large or small facility. We 
disagree that the recordkeeping is burdensome. If you are an NPDES 
permittee, you may use the stormwater drainage records required 
pursuant to 40 CFR 122.41(j)(2) and 122.41(m)(3) for SPCC purposes, 
thereby reducing the recordkeeping burden.
    Engineering methods. ``Equivalent'' measures referenced in the rule 
might, depending on good engineering practice, include using structures 
such as stand pipes designed to handle flow-through conditions at water 
flood oil production operations, where large volumes of water may be 
directed to oil storage tanks if water discharge lines on oil-water 
separators become plugged. Any alternate measures must provide 
environmental protection equivalent to the rule requirement.
    Industry standards. Industry standards that may assist an owner or 
operator with facility drainage include API Recommended Practice 51, 
``Onshore Oil and Gas Production Practices for Protection of the 
Environment.''
    Editorial changes and clarifications. In response to the 
commenter's suggestion, the reference to ``navigable waters'' becomes a 
reference to ``a discharge as described in Sec. 112.1(b).'' ``Central 
treating stations'' becomes ``separation and treating areas.'' Such 
areas might be centrally located or located elsewhere at the facility 
and might include both separation and treatment devices and equipment. 
The reference to ``rainwater is being drained'' becomes ``draining 
uncontaminated rainwater.'' We clarify that accumulated oil on 
rainwater must be disposed of in accord with ``legally approved 
methods,'' not ``approved methods.''

Section 112.9(b)(2)--Proposed as Sec. 112.9(c)(2)--Drainage Ditches, 
Accumulations of Oil

    Background. In 1991, we sought to clarify that oil as well as oil-
contaminated soil must be removed from field drainage ditches, road 
ditches, and the like. The current rule only requires removal of an 
``accumulation of oil.'' We also proposed that such accumulations be 
removed within 72 hours at the most.
    Comments. Applicability. One commenter asserted that this section 
does not apply to crude oil transfers from production fields into tank 
trucks because any discharges in the transfer process would be caught 
in a small

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sump or catchment basin. Another commenter asked if this section 
applied to cleanup of oil and oil-contaminated soil from diked areas.
    Inspection schedule. Another commenter suggested that we require 
inspections of field drainage ditches, etc., at monthly intervals and 
within 24 hours of a 25-year storm event.
    Accumulations of oil and oil-contaminated soil. Two commenters 
argued that EPA lacks authority to require cleanup of contaminated 
soil. Others asked for clarifications of the terms ``accumulation'' and 
``oil-contaminated soil.'' Another asked what cleanup standard EPA 
contemplated under this rule. The commenter elaborated, ``is 
accumulated oil and contaminated soil to be removed from diked areas 
under this provision?''
    72-hour cleanup standard. Several commenters argued that the 72-
hour standard for cleanup would preclude bioremediation or other 
cleanup techniques allowed by State and local law. Several commenters 
suggested other time periods, including ``as soon as practical,'' 
``within a timely manner.'' Some suggested no time standard is 
appropriate. Those commenters generally thought that a 72-hour period 
might be unrealistic in certain cases.
    Response to comments. Applicability. Crude oil transfers from 
production fields into tank trucks or cars are covered by the general 
requirements contained in Sec. 112.7(c) and (h), both of which require 
some form of secondary containment. Cleanup of oil, oil-contaminated 
soil, and oil-contaminated materials from field drainage ditches, road 
ditches, or other field drainage system is covered by this paragraph. 
In response to comment, we note that cleanup of oil from diked areas at 
onshore production facilities is not specifically covered by the rules. 
However, the presence of oil in diked areas may impair the quality of 
the dike or the capacity for secondary containment, and if so, the oil 
must be removed.
    Inspection schedule. We have retained the ``regularly scheduled 
intervals'' standard for inspections. This standard means regular 
inspections according to industry standards or on a schedule sufficient 
to prevent a discharge as described in Sec. 112.1(b). Whatever schedule 
for inspections is selected must be documented in the Plan. We decline 
to specify a specific interval because such an interval might become 
obsolete with changing technology.
    Accumulations of oil and oil-contaminated soil. We have adequate 
authority to require cleanup of an accumulation of oil, including on 
soil and other materials, because section 311(j)(1)(C) of the CWA 
provides EPA with the authority to establish procedures, methods, and 
equipment and other requirements for equipment to prevent discharges of 
oil. The broad definition of ``oil'' in CWA section 311(a)(1) covers 
``oil refuse'' and ``oil mixed with wastes other than dredged spoil.'' 
If field drainage systems allow the accumulation of oil on the soil or 
other materials at the onshore facility and that oil threatens 
navigable water or adjoining shorelines, then EPA has authority to 
establish a method or procedure, i.e., the removal of oil contaminated 
soil, to prevent that oil from becoming a discharge as described in 
Sec. 112.1(b). The cleanup standard under this paragraph requires the 
complete removal of the contaminated oil, soil, or other materials, 
either by removal, or by bioremediation, or in any other effective, 
environmentally sound manner.
    72-hour cleanup standard. We agree that the 72-hour cleanup 
standard might preclude bioremediation and have therefore deleted it. 
Instead we establish a standard of ``prompt cleanup.'' ``Prompt'' 
cleanup means beginning the cleanup immediately after discovery of the 
discharge or immediately after any actions necessary to prevent fire or 
explosion or other imminent threats to worker health and safety.
    Editorial changes and clarifications. ``Escaped from small leaks'' 
becomes ``resulted from any small discharge.'' We eliminate the term 
``oil-contaminated soil'' because oil must accumulate on something, 
such as materials or soil. We retain the term ``accumulation of oil,'' 
but elaborate on its meaning. ``Accumulation of oil'' means a discharge 
that causes a ``film or sheen'' within the field drainage system, or 
causes a sludge or emulsion there (see 40 CFR 110.3(b)). An 
accumulation of oil includes anything on which the oil gathers or 
amasses within the field drainage system. An accumulation of oil may 
include oil-contaminated soil or any other oil-contaminated material 
within the field drainage system. See also the discussion of 
``accumulation of oil'' included with the response to comments of 
Sec. 112.8(c)(10).

Proposed Section 112.9(c)(3)--Additional Requirements for Flood Events

    Background. In 1991, we proposed a new recommendation for oil 
production facilities in areas subject to flooding. We recommended that 
the Plan address additional precautionary measures related to flooding. 
In the discussion of the proposal, we referenced FEMA requirements.
    Comments. One commenter thought this provision should be a 
requirement rather than a recommendation. Another commenter suggested 
that exploration and production facilities located in flood plain areas 
should be adequately secured through proper mechanical/engineering 
methods to reduce the chance of loss of product. A third commenter 
suggested the following specific measures to be implemented: (1) 
Identify whether the facility is located in a floodplain in the Plan; 
(2) if the facility is located in a floodplain, the Plan should address 
to what extent it meets the minimum requirements of the National Flood 
Insurance Program (NFIP); and (3) if a facility does not meet the 
minimum requirements of the NFIP, the Plan should address appropriate 
precautionary and mitigation measures for potential flood-related 
discharges.
    Response to comments. We have deleted the recommendation because we 
do not wish to confuse the regulated public over what is mandatory and 
what is discretionary. These rules contain only mandatory requirements. 
However, we support the substance of the recommendation, and suggest 
that a facility in an area prone to flooding either follow the 
requirements of the NFIP or employ other methods based on good 
engineering practice to minimize damage to the facility from a flood.

Section 112.9(c)(1)--Proposed as Sec. 112.9(d)(1)--Materials and 
Construction--Bulk Storage Containers

    Background. In 1991, we reproposed the section on materials and 
construction of bulk storage containers with an added recommendation 
that containers conform to relevant industry standards.
    Comments. One commenter thought that the recommendation for use of 
industry standards should be a requirement. The commenter asked that at 
a date certain, all existing tanks must be upgraded to current 
standards, and that all new and reconstructed tanks must be subject to 
applicable codes. Another commenter suggested that the recommendation 
should not apply to crude oil storage tanks because local industry 
standards are more appropriate.
    Response to comments. Recommendation v. requirement. We are 
retaining the mandatory requirement to use no container for the storage 
of oil unless its material and construction are compatible with the 
material stored and the conditions of storage, as proposed. We have 
deleted the recommendation that materials, installation, and use of

[[Page 47128]]

new tanks conform with relevant portions of industry standards because 
we do not wish to confuse the regulated public over what is mandatory 
and what is discretionary. However, we endorse its substance. In most 
cases good engineering practice and liability concerns will prompt the 
use of industry standards. See Sec. 112.3(d)(1)(iii). In addition, a 
requirement is not necessary or desirable because local governmental 
standards on construction, materials, and installation sometimes 
control industry standards on these matters.
    Industry standards. Industry standards that may assist an owner or 
operator with materials for and construction of onshore bulk storage 
production facilities include: (1) API Specification 12B, ``Bolted 
Tanks for Storage of Production Liquids'; (2) API Specification 12D, 
``Field Welded Tanks for Storage of Production Liquids'; (3) API 
Specification 12F, ``Shop Welded Tanks for Storage of Production 
Liquids'; (4) API Specification 12J, ``Oil Gas Separators'; (5) API 
Specification 12K, ``Indirect-Type Oil Field Heaters'; and, (6) API 
Specification 12L, ``Vertical and Horizontal Emulsion Treaters.''
    Editorial changes and clarifications. ``Tank'' becomes 
``container.''

Section 112.9(c)(2)--Proposed as Sec. 112.9(d)(2)--Secondary 
Containment, Drainage

    Background. The SPCC Task force concluded that aboveground storage 
tanks without secondary containment pose a particularly significant 
threat to the environment. We noted that the proposed rule 
modifications would ``retain the current requirement for facility 
owners or operators who are unable to provide certain structures or 
equipment for oil spill prevention, including secondary containment, to 
prepare facility-specific contingency plans in lieu of prevention 
systems.'' 56 FR 54614. In 1991, we therefore reproposed the secondary 
containment requirements for onshore oil production facilities with a 
clarification. We clarified that secondary containment must include 
sufficient freeboard to allow for precipitation. The current rule 
requires that drainage from undiked areas must be safely confined in a 
catchment basin or holding pond. The proposed rule had modified this 
requirement to apply only to drainage from undiked areas ``showing a 
potential for contamination.''
    Comments. Secondary containment. See the discussion under 
Sec. 112.7(c) of secondary containment in general. One commenter 
suggested that the requirement was too vague and comprehensive to be 
applied to oil leases, which might cover hundreds of acres. Another 
asked how we would determine what is sufficient freeboard.
    Drainage. One commenter thought the drainage requirement was 
duplicative of NPDES requirements.
    Response to comments. Secondary containment. The requirement 
applies to oil leases of any size. Secondary containment is not 
required for the entire leased area, merely for the contents of the 
largest single container in the tank battery, separation, and treating 
facility installation, with sufficient freeboard to contain 
precipitation. In response to the comment as to how an owner or 
operator might determine how much freeboard is sufficient, we have 
revised the rule to provide that freeboard sufficient to contain 
precipitation is the standard. Freeboard sufficient to contain 
precipitation is freeboard installed according to industry standards, 
or in an amount sufficient to avert a discharge as described in 
Sec. 112.1(b). This standard is consistent with the amount of freeboard 
required in Sec. 112.8(c)(2).
    Drainage. We deleted the proposed reference to undiked areas 
``showing a potential for contamination'' because drainage from any 
undiked area poses a threat of contamination. When drainage from such 
areas is covered by stormwater discharge permits, that part of the BMP 
might be usable for SPCC purposes. There is no redundancy in 
recordkeeping requirements, because you can use your NPDES records for 
SPCC purposes.
    Industry standards. Industry standards that may assist an owner or 
operator with secondary containment at onshore production facilities 
include: (1) API Recommended Practice 51, ``Onshore Oil and Gas 
Production Practices for Protection of the Environment'; (2) NFPA 30, 
``Flammable and Combustible Liquids Code'; and, (3) BOCA, ``National 
Fire Prevention Code.''
    Editorial changes and clarifications. ``Tank battery and central 
treating plant installations'' becomes ``tank battery, separation, and 
treating facility installations.'' ``Contents of the largest single 
tank'' becomes ``capacity of the largest single container.'' With this 
change, this paragraph agrees with general secondary containment 
requirements found in Sec. 112.7(c). The reference to tanks ``in use'' 
was deleted because it is redundant. Containment for tanks or 
containers that are not permanently closed is already required. We 
deleted the phrase ``if feasible, or alternate systems, such as those 
outlined in Sec. 112.7(c)(1),'' because it is confusing when compared 
to the text of Sec. 112.7(d). Under Sec. 112.7(d), if secondary 
containment is not practicable, you must provide a contingency plan 
following the provisions of 40 CFR part 109, and otherwise comply with 
the requirements of Sec. 112.7(d). Furthermore, you are also free to 
provide alternate systems of secondary containment. We do not prescribe 
the method.

Section 112.9(c)(3)--Proposed as Sec. 112.9(d)(3)--Container Inspection

    Background. In 1991, we proposed that you must visually examine all 
containers of oil at onshore production facilities at least once a 
year. The current requirement is that you examine these containers ``on 
a scheduled periodic basis.'' We also proposed that you would be 
required to maintain the schedule and records of those examinations for 
a period of five years, irrespective of changes in ownership.
    Comments. Frequency of inspection. One commenter favored the 
proposal. One commenter suggested quarterly rather than annual 
inspections. Two commenters suggested triennial inspections. Other 
commenters suggested a frequency in accordance with API recommended 
standards.
    Extent of inspection. Several commenters thought that the 
inspections should be external only, and should not necessarily include 
the foundations and supports (as proposed) because of the number of 
containers that would be taken out of service with that requirement. 
Another commenter asserted that inspection of foundations and supports 
might not be possible due to foundation settlement or lack of space to 
perform the inspection.
    Response to comments. Frequency of inspection. We have maintained 
the current standard for frequency of inspection because we agree that 
inspections in accordance with industry standards are necessary. Those 
standards may change with changing technology, therefore, a frequency 
of ``periodically and upon a regular schedule'' preserves maximum 
flexibility and upholds statutory intent.
    Extent of inspection. We disagree that the inspection of containers 
should be limited to external inspection. Internal inspection is also 
necessary to detect possible flaws that could cause a discharge. The 
inspection must also include foundations and supports that are on or 
above the surface of the ground. If for some reason it is not 
practicable to inspect the foundations and supports, you may deviate 
from the requirement under Sec. 112.7(a)(2), if you explain your 
rationale for

[[Page 47129]]

nonconformance and provide equivalent environmental protection.
    Record maintenance. We have deleted the proposed requirement to 
maintain records of these inspections for five years, irrespective of 
ownership, because it is redundant with the general requirement in 
Sec. 112.7(e) to maintain Plan records. Section 112.7(e) requires 
record maintenance for three years. However, you should note that 
certain industry standards (for example, API Standard 653 or API 
Recommended Practice 12R1) may specify that an owner or operator 
maintain records for longer than three years.
    Industry standards. Industry standards that may assist an owner or 
operator with inspection of containers at onshore production facilities 
include: (1) API Recommended Practice 12R1, ``Recommended Practice for 
Setting, Maintenance, Inspection, Operation, and Repair of Tanks in 
Production Service''; and, (2) ``API Standard 653, ``Tank Inspection, 
Repair, Alteration, and Reconstruction.''
    Editorial changes and clarifications. ``Visually examine'' becomes 
``Visually inspect.'' ``All tanks'' becomes ``each container.'' 
``Foundation and supports of tanks above the ground surface'' becomes 
``Foundation and support of each container that is on or above the 
surface of the ground.''

Section 112.9(c)(4)--Proposed as Sec. 112.9(d)(4)--Good Engineering 
Practice

    Background. In 1991, we proposed to convert the current requirement 
for ``fail-safe'' engineering (which includes vacuum protection and 
other measures) of new and old tank battery installations into a 
recommendation. We also proposed that you reference appropriate 
industry standards.
    Comments. One commenter asserted that we should retain the original 
requirement to avoid confusion among the regulated community, help 
improve spill prevention, and because we proposed a similar requirement 
for bulk storage containers. Another commenter opposed the proposed 
recommendation because he believed the cost of such engineering would 
be prohibitive. Two commenters sought an exemption for small facilities 
on the same rationale. Similarly, some commenters opposed the proposed 
recommendation on vacuum protection because of the potential cost. None 
of the commenters provided their own cost estimates. Some commenters 
opposed the proposed recommendation relating to vacuum protection 
because of the potential cost, which they estimated as ``in excess of 
$100 per tank.''
    Response to comments. Good engineering practice. We agree with the 
commenter that we should retain this section as a requirement both to 
improve spill prevention and to avoid confusion among the regulated 
community because of the similar requirement for bulk storage 
containers at facilities other than production facilities. Therefore, 
there are no new costs. Nevertheless, you have flexibility as to which 
measures you use, and may choose the least expensive alternative listed 
in Sec. 112.9(c)(4). For example, should vacuum protection be too 
costly, you are free to use another alternative. Furthermore, you may 
also deviate from the requirement under Sec. 112.7(a)(2) if you can 
explain nonconformance and provide equivalent environmental protection 
by some other means. We revised the paragraph on vacuum protection to 
clarify that the rule addresses any type of transfer from the tank, not 
merely a pipeline run.
    Industry standards. Industry standards that may assist an owner or 
operator with alarm systems include: (1) API, ``Manual of Petroleum 
Measurement Standards''; (2) API Recommended Practice 51, ``Onshore Oil 
and Gas Production Practices for Protection of the Environment''; (3) 
API Recommended Practice 2350, ``Overfill Protection for Storage Tanks 
in Petroleum Facilities''; and, (4) NFPA 30, ``Flammable and 
Combustible Liquids Code.''
    Editorial changes and clarifications. ``Fail-safe'' engineering 
becomes ``good engineering practice,'' because fail-safe engineering is 
a misnomer. The change in terminology does not imply any substantive 
change in the level of environmental protection required, it is merely 
editorial. See the comments, and the discussion under ``Editorial 
changes and clarification,'' Sec. 112.8(c)(8). The same reasoning 
applies to this paragraph. We deleted the phrase ``as far as is 
practical,'' because it is confusing when compared to the text of 
Sec. 112.7(a)(2). Under Sec. 112.7(a)(2), you may explain your reasons 
for nonconformance, and provide equivalent environmental protection by 
some other means. We deleted the recommendation to reference 
appropriate industry standards because it was unnecessary. You must 
discuss actual standards used in the Plan. Section 112.3(d)(1)(iii) 
also requires the Professional Engineer to certify that he has 
considered applicable industry standards in the preparation of the 
Plan. Also in the introductory paragraph, the phrase ``Consideration 
shall be given to providing.* * *'' becomes, ``You must provide.* * *'' 
This change makes the language consistent with a companion paragraph 
dealing with good engineering design, i.e., Sec. 112.8(c)(8). In 
paragraph (c)(4)(i), ``regular rounds'' becomes ``regularly scheduled 
rounds.'' ``Spills'' becomes ``discharges.'' In paragraph (c)(4)(iv), 
the phrase ``where facilities are'' becomes ``where the facility is.'' 
Elsewhere ``tank'' becomes ``container.''

Section 112.9(d)(1)--Proposed as Sec. 112.9(e)(1)--Inspection of 
Aboveground Valves and Piping

    Background. In 1991, we proposed that you inspect monthly all 
aboveground valves and pipelines, and that you maintain records of such 
inspections for five years. The current requirement is that you examine 
such valves and pipelines ``periodically on a scheduled basis,'' and 
maintain the records of such inspections for three years.
    Comments. Editorial changes and clarifications. One commenter asked 
for clarifying language that the rule only applied to valves and piping 
associated with transfer operations.
    Applicability. Two commenters asked for an exemption from the 
requirements of this paragraph for small facilities.
    Frequency of inspections. Several commenters suggested alternate 
inspection intervals, such as every six months, or every year. Another 
commenter suggested that monthly inspections are meaningless because 
some unscrupulous operators might fill out inspection reports on dates 
when no problems are to be found. Other commenters suggested that we 
require a performance standard instead of a prescribed monthly 
inspection. One commenter suggested the proposed inspections standards 
for Sec. 112.9(e) were excessive for many small facilities. The 
commenter suggested that a standard defined by the licensed 
Professional Engineer who certifies the SPCC Plan could reflect the 
differing requirements that may apply under different equipment 
configurations as well as differing geographical and meteorological 
conditions. The commenter added that a generalized performance standard 
should be included that includes a minimum inspection interval, such as 
annual inspection, which could be altered to meet specific facility 
conditions.
    Recordkeeping. One commenter thought a five-year record retention 
period is excessive. Another commenter asked that we clarify that PE 
certification of these regular inspections and records is not required.
    Response to comments. Applicability. The rule must apply equally to 
large and

[[Page 47130]]

small facilities because failure to inspect piping and valves at any 
facility might lead to a discharge as described in Sec. 112.1(b).
    Frequency of inspections. We have retained the current inspection 
frequency of periodic inspections, but editorially changed it to ``upon 
a regular schedule.'' Our decision accords with the comment which 
sought a performance standard instead of a prescribed monthly 
inspection. The standard of inspections ``upon a regular schedule'' 
means in accordance with industry standards or at a frequency 
sufficient to prevent discharges as described in Sec. 112.1(b). 
Whatever frequency of inspections is selected must be documented in the 
Plan.
    Recordkeeping. We agree that a five-year record retention period is 
longer than necessary and have deleted the proposed requirement in 
favor of the general requirement in Sec. 112.7(e) to maintain records 
for three years. However, comparison records for compliance with 
certain industry standards may require an owner or operator to maintain 
records for longer than three years. PE certification of these 
inspections and records is not required.
    Editorial changes and clarifications. ``Examine'' becomes 
``inspect.'' We agree with the commenter who asked for clarification 
that the rule applies only to inspections related to transfer 
operations and have amended the rule to reflect that. A transfer 
operation is one in which oil is moved from or into some form of 
transportation, storage, equipment, or other device, into or from some 
other or similar form of transportation, such as a pipeline, truck, 
tank car, or other storage, equipment, or device.

Section 112.9(d)(2)--Proposed as Sec. 112.9(e)(2)--Salt Water Disposal 
Facilities

    Background. In 1991, we reproposed without change the current 
requirements on the examination of salt water (oil field brine) 
disposal facilities. The current requirement is that you examine these 
facilities ``often.'' However, we have recommended weekly examination 
as an appropriate engineering standard for most facilities. 56 FR 
54624. We noted that low temperature conditions, sudden temperature 
changes, or periods of low flow rates may require more frequent 
inspections.
    Comments. Applicability. One commenter suggested that the 
requirement to examine these facilities should not apply to storage 
facilities with de minimis amounts of oil.
    Sudden change in temperature. Another commenter asked for 
clarification of what ``a sudden change in temperature'' means. The 
commenter assumed that it meant a sudden drop that could cause system 
upsets.
    Response to comments. Applicability. The rule applies to any 
regulated facility with salt water disposal if the potential exists to 
discharge oil in amounts that may be harmful, as defined in 40 CFR 
110.3. This standard is necessary to protect the environment.
    Sudden change in temperature. A sudden change in temperature means 
any abrupt change in temperature, either up or down, which could cause 
system upsets.
    Frequency of inspections. Inspections of these facilities must be 
conducted ``often.'' ``Often'' means in accordance with industry 
standards, or more frequently, if as noted, conditions warrant. 
Whatever frequency of inspections is chosen must be documented in the 
Plan.
    Editorial changes and clarifications. ``Examine'' becomes 
``inspect.'' ``Oil discharge'' becomes ``discharge,'' because the term 
``oil'' is redundant in the definition of ``discharge.''

Section 112.9(d)(3)--Proposed as Sec. 112.9(e)(3)--Flowline Maintenance

    Background. In 1991, we reproposed the current requirements for 
flowline maintenance. We proposed a recommendation, rather than a 
requirement, that the program include certain specifics, because of 
differences in the circumstances of locations, staffing, and design for 
production facilities. We suggested that monthly examinations are 
appropriate for most facilities.
    Comments. Applicability. Two commenters asked for a small facility 
exemption for this recommendation.
    Frequency of inspections. Several commenters suggested that the 
recommendation refer to periodic instead of monthly examinations. 
Others suggested annual or quarterly inspections. One commenter said 
that monthly inspection of gathering lines buried in the colder parts 
of the Appalachian basin is impossible.
    Corrosion protection. Several commenters asserted that the 
provision for corrosion protection for the bare steel pipe used for 
gathering line systems in the Appalachians is impossible because the 
cost of coated lines and cathodic protection is prohibitive. None of 
the commenters provided their own cost estimates.
    Transfer operation. One commenter asked for clarification of the 
term ``oil production facility transfer operation.'' The commenter 
suggested that a definition of the term would improve compliance.
    Response to comments. Applicability. A program of flowline 
maintenance is necessary to prevent discharges both at large and small 
facilities. However, we have deleted the proposed recommendation 
regarding the specifics of the program from the rule. We took this 
action because we are not including recommendations in the rule in 
order not to confuse the public over what is mandatory and what is 
discretionary. This rule contains only mandatory requirements.
    Frequency of inspections. In the proposed recommendation we 
suggested that you conduct monthly inspections for a flowline 
maintenance program. We now recommend that you conduct inspections 
either according to industry standards or at a frequency sufficient to 
prevent a discharge as described in Sec. 112.1(b). Under 
Sec. 112.3(d)(1)(iii), the Professional Engineer must certify that the 
Plan has been prepared in accordance with good engineering practice, 
including consideration of applicable industry standards.
    Corrosion protection, flowline replacement. While we have deleted 
the recommendation from rule text due to reasons explained above and 
therefore, the rule imposes no new costs, we recommend corrosion 
protection, we recommend corrosion protection, and flowline replacement 
when necessary, because those measures help to prevent discharges as 
described in Sec. 112.1(b).
    Transfer operation. A transfer operation is one in which oil is 
moved from or into some form of transportation, storage, equipment, or 
other device, into or from some other or similar form of 
transportation, such as a pipeline, truck, tank car, or other storage, 
equipment, or device.
    Editorial changes and clarifications. ``Spills'' becomes 
``discharges.'' The phrase ``from this source'' becomes ``from each 
flowline.''

Section 112.10--Introduction--Onshore Oil Drilling and Workover 
Facilities

    Background. This paragraph is a new one, not proposed in 1991, but 
editorially added to allow us to rewrite the section in the active 
voice. Since the owner or operator is the person with responsibility to 
implement a Plan, the mandates of the rule are properly addressed to 
him, except as specifically noted.

Section 112.10(a)--General and Specific Requirements

    Background. This is a new paragraph that merely references the 
general

[[Page 47131]]

requirements which all facilities must meet as well as the specific 
requirements that facilities in this category must meet.
    Comments. One commenter asked for a definition of ``onshore 
drilling and workover facilities.''
    Editorial changes and clarifications. The new definition for 
``production facility'' in Sec. 112.2 includes the procedures, methods, 
and equipment referenced in this section, making a definition of 
``onshore drilling and workover facilities'' unnecessary. ``Spill 
prevention'' becomes ``discharge prevention.'' To ``address'' 
requirements becomes to ``meet'' requirements.

Section 112.10(b)--Mobile Facilities

    Background. In 1991, we reproposed the current rule on the location 
of mobile facilities without substantive change.
    Comments. Editorial changes and clarifications. One commenter asked 
that the requirement be limited to discharges to navigable waters.
    Site location. One commenter opposed the requirement on the 
location of mobile facilities because the facility contractor has 
absolutely no control over the location of the rig unit. The commenter 
added that the contractor is instructed by the site owner/operator 
where to place the rig unit generally, and the sites are where oil and 
gas are expected to be located. The physical location of the well site 
is constructed by and maintained by the owner/operator of the lease. 
The contractor has no input as to site design nor responsibility for 
its maintenance.
    Response to comments. Site location. We agree with the commenter 
that the contractor is not normally responsible for site location, nor 
site design or maintenance. Such decisions are the responsibility of 
the facility owner or operator. The owner or operator of the facility 
has the responsibility to locate equipment so as to prevent discharges 
as described in Sec. 112.1(b).
    Editorial changes and clarifications. The applicable limitation on 
discharges in the rule tracks the statute. The commenters requested 
that discharges be limited to discharges to ``navigable waters.'' 
However, the correct scope of discharge prevention is not merely 
navigable waters, but the entire range of protected resources described 
in Sec. 112.1(b). We therefore use the phrase ``a discharge as 
described in Sec. 112.1(b).''

Section 112.10(c)--Secondary Containment--Catchment Basins or Diversion 
Structures

    Background. In 1991, we reproposed without substantive change the 
current requirements for secondary containment. We received no comments 
on the proposal. Therefore, we have promulgated it as proposed, with 
minor editorial changes.
    Industry standards. Industry standards that may assist an owner or 
operator with secondary containment at onshore oil drilling and 
workover facilities include: (1) API Recommended Practice 52, ``Land 
Drilling Practices for Protection of the Environment''; (2) NFPA 30, 
``Flammable and Combustible Liquids Code''; and, (3) BOCA, ``National 
Fire Prevention Code.''
    Editorial changes and clarifications. ``Spills'' becomes 
``discharges.'' The words ``depending on the location'' were deleted 
because they were confusing when compared with the text of 
Sec. 112.7(d). If a catchment basin or diversion structure or other 
form of secondary containment is not practicable from the standpoint of 
good engineering practice, under Sec. 112.7(d) you must provide a 
contingency plan following the provisions of 40 CFR part 109, and 
otherwise comply with Sec. 112.7(d).

Section 112.10(d)--Blowout Prevention (BOP)

    Background. In 1991, we proposed that blowout prevention (BOP) 
assembly would only be required ``when necessary.'' The rationale was 
that a BOP assembly is not necessary where pressure is not great enough 
to cause a blowout (gauge negative) and is not required in all cases. 
We noted that the necessity of BOP assembly hinges on the ``history of 
the pressures encountered when drilling on the oil reservoir.'' When 
that history is unknown, BOP assembly is required.
    Comments. Several commenters urged modification of the rule to 
exclude well service jobs that may not need BOP assembly, such as the 
installation of a rod pumping unit, or the batch treatment of a well 
with corrosion inhibitor.
    Response to comments. Service jobs. Where BOP assembly is not 
necessary, as for certain routine service jobs, such as the 
installation of a rod pumping unit, or the batch treatment of a well 
with corrosion inhibitor, you may deviate from the requirement under 
Sec. 112.7(a)(2), and explain its absence in the Plan. When BOP 
assembly is unnecessary because pressures are not great enough to cause 
a blowout, it is likewise unnecessary to provide equivalent 
environmental protection.
    Industry standards. Industry standards that may assist an owner or 
operator with blowout prevention assembly include: (1) API Recommended 
Practice 16E, ``Design of Control Systems for Drilling Well Control 
Equipment''; (2) API Recommended Practice 53, ``Blowout Prevention 
Equipment Systems for Drilling Operations''; (3) API Specification 16A, 
``Drill Through Equipment''; and, (4) API Specification 16D, ``Control 
Systems for Drilling Well Control Equipment.''
    Editorial changes and clarifications. We deleted the phrase ``as 
necessary'' from the requirement, because it is confusing when compared 
to the text of Sec. 112.7(a)(2). When BOP assembly is unnecessary and 
therefore no alternate measure is required, you may deviate from the 
requirement under Sec. 112.7(a)(2) if you explain your reasons for 
nonconformance. We have deleted as surplus the last sentence of the 
rule requiring that casing and BOP installations must be in accordance 
with State regulatory requirements. Adherence to State regulatory 
requirements is mandatory under State law in any case. The phrase ``is 
expected to be encountered'' becomes ``may be encountered.''

Section 112.11--Introduction--Offshore Oil Drilling, Production, or 
Workover Facilities

    Background. We added an introduction as an editorial device to 
allow us to rewrite the section in the active voice. Because the owner 
or operator is the person with responsibility to implement a Plan, the 
mandates of the rule are properly addressed to him, except as 
specifically noted.

Section 112.11(a)--General and Specific Requirements--Offshore Oil 
Drilling, Production, or Workover Facilities

    Background. This is a new paragraph that merely references the 
general requirements which all facilities must meet as well as the 
specific requirements that facilities in this category must meet.
    Comments. State rules. One commenter thought Sec. 112.11 should be 
deleted because current State rules provide adequate spill protection 
in inland water areas such as lakes, rivers, and wetlands.
    Response to comments. State rules. We disagree with the commenter 
that these rules are unnecessary because not every State has rules to 
protect offshore drilling, production, and workover facilities. While 
some States may have rules, some State rules may not be as stringent as 
the Federal rules. In any case, Congress has intended us to establish a 
nationwide Federal program to protect the environment from the

[[Page 47132]]

dangers of discharges as described in Sec. 112.1(b) posed by this class 
of facilities. Therefore, we have retained the section, as modified. We 
note, however, that if you have a State SPCC plan or other regulatory 
document acceptable to the Regional Administrator that meets all 
Federal SPCC requirements, you may use it as an SPCC Plan if you cross 
reference the State or other requirements to the Federal requirement. 
If it meets only some, but not all Federal SPCC requirements, you must 
supplement it so that it meets all of the SPCC requirements.
    Editorial changes and clarifications. ``Spill prevention'' becomes 
``discharge prevention.'' The obligation to ``address'' requirements 
and procedures becomes the obligation to ``meet'' them.

Proposed Section 112.11(b)--Definition Reference; MMS Jurisdiction

    Background. The proposed 1991 section referenced the definition of 
``offshore oil drilling, production, and workover facility,'' which is 
now encompassed within the definition of ``production facility'' in 
Sec. 112.2. A new sentence would have referenced the exemption of 
facilities subject to Minerals Management Service (MMS) Operating 
Orders, notices, and regulations from the SPCC rule. MMS jurisdiction 
is outlined in Appendix B to part 112.
    Comments. One commenter suggested that we delete the reference to 
the proposed definition and to the applicability section.
    Response to comments. We agree. Since none of the proposed language 
is mandatory, we have deleted it because we have included only mandates 
in this rule so as not to confuse the regulated public over what is 
required and what is discretionary.

Section 112.11(b)--Proposed as Sec. 112.11(c)--Facility Drainage

    Background. In 1991, we reproposed the current section on facility 
drainage with the modification to require removal of collected material 
at least once a year. The rationale was to prevent a buildup of 
accumulated oils. We noted that a protracted removal period could lead 
to an accidental excess buildup and resultant overflow.
    Comments. Two commenters recommended deletion of the proposed 
requirement to remove collected oil as often as necessary, but at least 
once a year, because the current requirement is sufficient.
    Response to comments. Removal of collected oil. EPA agrees with the 
commenter's suggestion that the current rule is sufficient to prevent 
discharges as described in Sec. 112.1(b), and therefore we have deleted 
the ``at least once a year'' standard. You must remove collected oil as 
often as is necessary to prevent such discharges.
    Editorial changes and clarifications. ``Discharging oil as 
described in Sec. 112.1(b)(1)'' becomes ``having a discharge as 
described in Sec. 112.1(b).'' In the second sentence, we deleted the 
phrase ``or equivalent collection system sufficient,'' because it is 
confusing when compared to the text of Sec. 112.7(a)(2). You may 
deviate from a requirement under Sec. 112.7(a)(2) if you explain your 
reasons for nonconformance, and provide equivalent environmental 
protection.

Section 112.11(c)--Proposed as Sec. 112.11(d)--Sump Systems

    Background. In 1991, we proposed to clarify language in current 
rule that a regularly scheduled maintenance program is a monthly 
preventive maintenance program.
    Comments. Frequency of inspections. One commenter recommended that 
a semi-annual inspection and testing program of the liquid removal 
system, instead of monthly inspection and testing would be preferable.
    Response to comments. Frequency of inspections. We have retained 
the current rule language requiring a ``regularly scheduled'' 
preventive maintenance program because we believe that the frequency of 
maintenance should be in accordance with industry standards or 
frequently enough to prevent a discharge as described in Sec. 112.1(b). 
Whatever schedule is chosen must be documented in the Plan.
    Editorial changes and clarifications. We deleted the phrase ``or 
equivalent method'' from the first sentence because it is confusing 
when compared to the text of Sec. 112.7(a)(2). You may deviate from a 
requirement under Sec. 112.7(a)(2) if you explain your reasons for 
nonconformance and provide equivalent environmental protection.

Section 112.11(d)--Proposed as Sec. 112.11(e)--Discharge Prevention 
Systems for Separators and Treaters

    Background. In 1991, we reproposed without substantive change the 
current rule on discharge prevention systems for separators and 
treaters. We received no comments.
    Editorial changes and clarifications. ``Escape'' of oil becomes 
``discharge'' of oil. ``Oil discharges'' becomes ``discharge of oil.'' 
We deleted the phrase from the last sentence which allows ``using other 
feasible alternatives to prevent oil discharges,'' because it is 
confusing when compared to the text of Sec. 112.7(a)(2). You may 
deviate from a requirement under Sec. 112.7(a)(2) if you explain your 
reasons for nonconformance and provide equivalent environmental 
protection.

Section 112.11(e)--Proposed as Sec. 112.11(f)--Atmospheric Storage or 
Surge Containers; Alarms

    Background. In 1991, we reproposed without substantive change the 
current paragraph on alarm systems for atmospheric storage or surge 
containers. We received no comments. Therefore, we have promulgated the 
rule as proposed, with only minor editorial changes.
    Editorial changes and clarifications. ``Oil discharges'' becomes 
``discharges.'' We added the words ``that activate an alarm or control 
the flow'' to clarify that these activities, along with ``otherwise'' 
controlling discharges, are the purpose of the sensing devices we 
reference in the paragraph. The phrase ``to activate'' becomes ``that 
activate,'' and we add the word ``otherwise'' before ``prevent 
discharges.'' We deleted the phrase ``or other acceptable 
alternatives,'' because it is confusing when compared to the text of 
Sec. 112.7(a)(2). You may deviate from a requirement under 
Sec. 112.7(a)(2) if you explain your reasons for nonconformance and 
provide equivalent environmental protection.

Section 112.11(f)--Proposed as Sec. 112.11(g)--Pressure Containers; 
Alarm Systems

    Background. In 1991, we reproposed the current rule concerning 
pressure tanks without substantive change. We received no comments. 
Therefore, we have promulgated the rule as proposed, with minor 
editorial changes.
    Editorial changes and clarifications. ``Tanks'' becomes 
``containers.'' ``Oil discharges'' becomes ``discharges.'' We deleted 
the phrase ``or with other acceptable alternatives to prevent 
discharges,'' because it is confusing when compared to the text of 
Sec. 112.7(a)(2). You may deviate from a requirement under 
Sec. 112.7(a)(2) if you explain your reasons for nonconformance and 
provide equivalent environmental protection.

Section 112.11(g)--Proposed as Sec. 112.11(h)--Corrosion Protection

    Background. In 1991, we reproposed the current paragraph requiring 
corrosion protection for containers at facilities subject to this 
section. We added a recommendation that you follow National Association 
of

[[Page 47133]]

Corrosion Engineers standards for corrosion protection.
    Comments. Industry standards. One commenter suggested that we 
remove the last sentence, which is advisory, and addresses industry 
standards of the National Association of Corrosion Engineers, or make 
it a requirement (at least for new construction). Another commenter 
suggested that the rule be modified to incorporate other industry 
recommended practices relative to corrosion control, such as those of 
STI and API. The commenter specifically recommended STI Recommended 
Practice R892-89, ``Recommended Practice for Corrosion Protection of 
Underground Steel Piping Associated with Underground Storage and 
Dispensing Systems,'' and STI Recommended Practice 893-89, 
``Recommended Practice for External Corrosion of Shop Fabricated 
Aboveground Steel Storage Tank Floors.''
    Response to comments. Industry standards. In response to the 
comment, we have deleted the recommendation because we do not wish to 
confuse the regulated community over what is mandatory and what is 
discretionary. These rules contain only mandatory requirements. We 
expect that facilities will follow industry standards for corrosion 
protection as well as other matters (see Sec. 112.3(d)(iii)), but 
decline to prescribe particular standards in the rule text because 
those standards are subject to change, and we will not incorporate a 
potentially obsolescent standard into the rules.
    Industry standards. Industry standards suggested by a commenter 
that may assist an owner or operator with corrosion include: (1) 
National Association of Corrosion Engineer standards; (2) STI 
Recommended Practice R892, ``Recommended Practice for Corrosion 
Protection of Underground Steel Piping Associated with Underground 
Storage and Dispensing Systems,'' and, (3) STI Recommended Practice 
893, ``Recommended Practice for External Corrosion of Shop Fabricated 
Aboveground Steel Storage Tank Floors.''
    Editorial changes and clarifications. ``Tanks'' becomes 
``containers.''

Section 112.11(h)--Proposed as Sec. 112.11(i)--Pollution Prevention 
System Procedures

    Background. In 1991, we reproposed without substantive change the 
current requirements concerning written procedures for inspecting and 
testing pollution prevention equipment and systems. We received no 
substantive comments. Therefore, we have promulgated the rule as 
proposed with minor editorial changes.
    Editorial changes and clarifications. ``As part of the SPCC Plan'' 
becomes ``within the Plan.''

Section 112.11(i)--Proposed as Sec. 112.11(j)--Pollution Prevention 
Systems; Testing and Inspection

    Background. In 1991, we reproposed the current rule on testing and 
inspection of pollution prevention systems. Additionally, we proposed 
that simulated spill testing must be the preferred method to test and 
inspect oil spill prevention equipment and systems. We also proposed 
that pollution prevention systems must be tested at least monthly. The 
current standard calls for testing and inspection ``on a scheduled 
periodic basis.''
    Comments. Some commenters suggested that simulation testing on a 
monthly basis is excessive. Commenters suggested instead testing on a 
semi-annual or annual basis.
    Response to comments. Frequency of testing. We have retained the 
current requirement for testing on a ``scheduled periodic basis'' 
commensurate with conditions at the facility because we believe that 
testing should follow industry standards or be conducted at a frequency 
sufficient enough to prevent a discharge as described in Sec. 112.1(b) 
rather than any prescribed time frame. Whatever frequency is chosen 
must be documented in the Plan.
    Editorial changes and clarifications. In the first sentence, ``or 
other appropriate regulations'' becomes ``and any other appropriate 
regulations.'' In the second sentence, ``spill testing'' becomes 
``simulated discharges for testing.'' We have deleted from the last 
sentence the phrase ``unless the owner or operator demonstrates that 
another method provides equivalent alternative protection'' because it 
is confusing when compared to the text of Sec. 112.7(a)(2). You may 
deviate from a requirement under Sec. 112.7(a)(2) if you explain your 
reasons for nonconformance and provide equivalent environmental 
protection.

Section 112.11(j)--Proposed as Sec. 112.11(k)--Surface and Subsurface 
Well Shut-in Valves and Devices

    Background. In 1991, we reproposed the current section concerning 
surface and subsurface well shut-in valves and devices. We proposed an 
additional requirement that records for each well must be kept for five 
years. We received no substantive comments. Therefore, we have 
promulgated the rule as proposed, with minor editorial changes.
    Editorial changes and clarifications. In today's rule, we kept the 
recordkeeping requirement, but deleted language requiring maintenance 
of those records for five years. The effect of the deletion is that 
records become subject to the general three-year recordkeeping 
requirement. See Sec. 112.7(e). You may keep the records as part of the 
Plan or may keep them with the Plan.

Section 112.11(k)--Proposed as Sec. 112.11(l)--Blowout Prevention

    Background. In 1991, we reproposed the current rule concerning 
blowout prevention without substantive change.
    Comments. One commenter suggested that there are occasions when 
blowout prevention is not warranted or impractical to implement and 
that there should be an exception for drilling below conductor casing.
    Response to comments. Alternatives. The question of whether blowout 
prevention is warranted or impractical or not for drilling below 
conductor casing is one of good engineering practice. Acceptable 
alternatives may be permissible under the rule permitting deviations 
(Sec. 112.7(a)(2)) when the owner or operator states the reasons for 
nonconformance and provides equivalent environmental protection.
    Industry standards. Industry standards that may assist an owner or 
operator with offshore blowout prevention assembly and well control 
systems include: (1) API Recommended Practice 16E, ``Design of Control 
Systems for Drilling Well Control Equipment''; (2) API Recommended 
Practice 53, ``Blowout Prevention Equipment Systems for Drilling 
Operations''; (3) API Specification 16A, ``Drill Through Equipment''; 
(4) API Specification 16C, ``Choke and Kill Systems''; and, (5) API 
Specification 16D, ``Control Systems for Drilling Well Control 
Equipment.''
    Editorial changes and clarifications. ``BOP preventor assembly'' 
becomes ``BOP assembly.'' We deleted the last sentence of the paragraph 
referring to adherence to State rules because we are not incorporating 
State rules into the SPCC rule and adherence to State rules is required 
under State law whether we state it or not. The phrase ``expected to be 
encountered'' becomes ``may be encountered.''

Proposed Sec. 112.11(m)--Extraordinary Well Control Measures

    Background. In 1991, we proposed to change the current requirements 
on extraordinary well control measures for emergency conditions to 
recommendations. The rationale was

[[Page 47134]]

that we would review these measures in the context of response 
planning.
    Comments. One commenter suggested that the paragraph should be 
deleted because it is advisory, or made a requirement.
    Response to comments. In response to comment, we have deleted the 
text of the recommendations from the rules because we do not wish to 
confuse the regulated community over what is mandatory and what is 
discretionary. However, we endorse its substance. This rule contains 
only mandatory requirements.

Section 112.11(l)--Proposed as Sec. 112.11(n)--Manifolds

    Background. In 1991, we reproposed the current requirements 
concerning manifolds without substantive change. We received no 
comments on the proposal. Therefore, we have promulgated the rule as 
proposed.

Section 112.11(m)--Proposed as Sec. 112.11(o)--Flowlines, Pressure 
Sensing Devices

    Background. In 1991, we reproposed the current requirements 
concerning pressure sensing devices and shut-in valves for flowlines 
without substantive change. We received no comments on the proposal. 
Therefore, we have promulgated the rule as proposed.

Section 112.11(n)--Proposed as Sec. 112.11(p)--Piping; Corrosion 
Protection

    Background. In 1991, we reproposed the current requirements 
concerning corrosion protection for piping appurtenant to the facility 
without substantive change. We also proposed to change into a 
recommendation the current requirement that the method used, such as 
protective coatings or cathodic protection, be discussed.
    Comments. One commenter suggested that we remove the second 
sentence, which is advisory.
    Response to comments. In response to comment, we have deleted the 
recommendation to discuss the method of corrosion protection, because 
it is surplus. In your SPCC Plan, you must discuss the method of 
corrosion protection you use. See 112.7(a)(1).

Section 112.11(o)--Proposed as Sec. 112.11(q)--Sub-Marine Piping; 
Environmental Stresses

    Background. In 1991, we reproposed the current requirements 
concerning environmental stress against sub-marine piping appurtenant 
to facilities without substantive change. We received no comments. 
Therefore, we have promulgated the rule as proposed, with minor 
editorial changes.
    Editorial changes and clarifications. We have rewritten the rule in 
the active voice. We also deleted the proposed recommendation because 
this rule contains only mandatory items, and because the recommendation 
is redundant. Whatever manner of protection is chosen to protect sub-
marine piping must be discussed in the Plan.

Section 112.11(p)--Proposed as Sec. 112.11(r)--Inspections of Sub-
Marine Piping

    Background. In 1991, we reproposed the current requirements 
concerning the inspection of sub-marine piping appurtenant to 
facilities without substantive change. We received no comments. 
Therefore, we have promulgated the rule as proposed, with minor 
editorial changes.
    Editorial changes and clarifications. The proposal to require 
maintenance of records for five years was deleted because under 
Sec. 112.7(e) of today's rule, all records must be kept for three 
years. We clarify that you must inspect or test the piping. Because 
visual inspection of sub-marine piping may not always be possible, we 
allow testing as an alternative. We encourage inspection or testing 
pursuant to industry standards or at a frequency sufficient to prevent 
a discharge as described in Sec. 112.1(b). Whatever inspection schedule 
you select must be documented in the Plan.

Proposed Sec. 112.11(s)--Written Instructions for Contractors

    Background. In 1991, we proposed to change into a recommendation 
the current requirement that you prepare written instructions for 
contractors and subcontractors whenever contract activities involve 
servicing a well, or systems appurtenant to a well or pressure vessel. 
The current rule requires that you keep the instructions at the 
facility. We note in the proposed rule that under certain 
circumstances, you may require the presence of your representative at 
the facility to intervene when necessary to prevent a discharge as 
described in Sec. 112.1(b).
    Comments. One commenter wrote that the proposal creates two serious 
problems. First, that since the contractor is hired to perform special 
services, he is able to do his work more safely if he is allowed to 
direct his own activities. Second, operators might expose themselves to 
various types of liability by virtue of the degree of control exercised 
over contractors. A second commenter suggested editorial revisions to 
the recommendation, and subsequent sentences.
    Response to comments. We have decided to delete the proposed 
recommendation because we do not wish to confuse the regulated 
community over what is mandatory and what is discretionary. This rule 
contains only mandatory requirements.

Subparts C and D

    Background. In 1995, Congress enacted the Edible Oil Regulatory 
Reform Act (EORRA), 33 U.S.C. 2720. That statute mandates that most 
Federal agencies differentiate between and establish separate classes 
for various types of oils, specifically: animal fats and oils and 
greases, fish and marine mammal oils; oils of vegetable origin; and, 
other oils and greases, including petroleum and other non-petroleum 
oils. In differentiating between these classes of oils, Federal 
agencies are directed to consider differences in the physical, 
chemical, biological, and other properties, and in the environmental 
effects, of the classes.
    In 1991, EPA proposed to reorganize the SPCC rule based on facility 
type. The rationale for that reorganization is to clarify SPCC Plan 
requirements for different types of facilities. While we have 
reorganized the rule to provide requirements for different types of 
facilities, we also provide requirements for different types of oil in 
this rulemaking. To make this change, we have divided the rule into 
subparts. Subpart A consists of an applicability section, definitions, 
and general requirements for all facilities. Subparts B and C outline 
the requirements for different types of oils. Subpart B is for 
petroleum oils and non-petroleum oils, except for animal fats and 
vegetable oils. Subpart C is for animal fats and oils and greases, and 
fish and marine mammal oils; and for vegetable oils, including oils 
from seeds, nuts, fruits, and kernels. Subpart D is for response. 
Subparts B and C are divided into sections to reflect the differing 
types of facilities for each type of oil. Subpart D is for response 
requirements.
    Therefore, as noted above, we have divided the requirements of the 
rule by subparts for the various classes of oils listed in EORRA. 
Because at the present time EPA has not proposed differentiated 
requirements for public notice and comment, the requirements for 
facilities storing or using all classes of oil will remain the same. 
However, we have published an advance notice of proposed rulemaking 
seeking comments on how we might differentiate requirements for 
facilities storing or using the various classes of oil. 64 FR

[[Page 47135]]

17227, April 8, 1999. After considering these comments, if there is 
adequate justification for differentiation, we will propose a rule.

Proposed Sec. 112.20(f)(4)--Capacity of Facilities Storing Process 
Water/Wastewater for Response Plan Purposes

    Background. In 1997, we proposed to add a new paragraph to 
Sec. 112.20(f) to provide a method for facility response plan purposes 
to calculate the oil storage capacity of storage containers storing a 
mixture of process water/wastewater with 10% or less of oil. This 
proposal for certain systems that treat process water/wastewater would 
be applicable at certain facilities required to prepare a facility 
response plan. It would have no effect on facilities required to 
prepare response plans because they transfer oil over water and have a 
total oil storage capacity greater than or equal to 42,000 gallons. 
Likewise, the proposal would have no effect on the method of 
calculating capacity for purposes of SPCC Plans. Under the proposal, we 
would not count the entire capacity of process water/wastewater 
containers with 10% or less of oil in the capacity calculation to 
determine whether a facility must prepare a facility response plan. We 
only would count the oil portion of that process water/wastewater 
contained in Sec. 112.20(f)(2), and therefore response planning is not 
necessary.
    Today, we are withdrawing the proposal because it is no longer 
necessary. It is unnecessary because we have exempted from part 112 any 
facility or part thereof (except at oil production, oil recovery, and 
oil recycling facilities) used exclusively for wastewater treatment and 
not to satisfy any requirement of part 112. See the discussion under 
Sec. 112.1(d)(6). The exemption in Sec. 112.1(d)(6) applies to the 
types of facilities treating wastewater that would have been allowed to 
calculate a reduced storage capacity if the percentage of oil in the 
mixture were 10 percent or less.

Section 112.20(h)--Facility Response Plan Format

    Background. In 1997, we proposed to amend the requirements for 
formatting of a facility response plan to clarify that an Integrated 
Contingency Plan (ICP) or other plan format acceptable to the Regional 
Administrator is allowable to serve as a facility response plan if it 
meets all facility response plan requirements. Our intent was to track 
language in the SPCC rule allowing the Regional Administrator similar 
authority to accept differing formats for SPCC Plans. However, the 
Regional Administrator already has the authority to accept differing 
formats for response plans, and the existing facility response plan 
requirements already provide for cross-referencing. See Sec. 112.20(h). 
Therefore, new rule language was unnecessary, and the proposal tracked 
current language. Today, we have made only a minor editorial change in 
rule language.
    Comments. Acceptable formats. Most commenters favored the proposal. 
One commenter suggested that the rule should specifically mention the 
ICP. Another requested that State FRP equivalents be accepted. Several 
commenters criticized the proposal; one calling the ICP concept ``over-
rated.'' One commenter thought that the rule makes the ICP mandatory. 
Another commenter noted that the proposed rule is identical to the 
current rule.
    Partially acceptable formats. One commenter asked if an operator 
would have to integrate all parts of an ICP with a response plan or if 
he would have the option to integrate parts of the ICP with the SPCC 
Plan.
    PE certification. One commenter asked how an ICP would work, i.e., 
whether the PE would be certifying the SPCC portion, the FRP portion, 
or both.
    Response to comments. Acceptable formats. It is not necessary for 
the rule to mention the ICP or any other format specifically because 
the rule already allows the Regional Administrator flexibility to 
accept any format that meets all Federal requirements. See 
Sec. 112.20(h). You may use the ICP, a State response plan, or other 
format acceptable to the Regional Administrator, at your option. We do 
not require use of any alternative format, but merely give you the 
option to do so.
    The commenter is correct that the proposed rule is identical to the 
current rule. The current rule allows the submission of an ``equivalent 
response plan that has been prepared to meet State or other Federal 
requirements.''
    Partially acceptable formats. You have the option to integrate any 
or all parts of an ICP with your response plan. This gives you 
flexibility in formatting. Similar to SPCC Plans, the Regional 
Administrator may accept partial use of alternative formats.
    PE certification. PE certification is only required for the SPCC 
portion of any ICP.
    Editorial changes and clarifications. We added the words 
``acceptable to the Regional Administrator'' in the first sentence 
after the words ``response plan.''

Appendix C--Substantial Harm Criteria

    Background. In 1997, we proposed changes to Appendix C which would 
track proposed amendments to Sec. 112.20(f)(4) regarding calculating 
the oil storage capacity of aboveground storage containers storing a 
mixture of process water/wastewater within 10% or less of oil. Because 
we have withdrawn the proposed changes to Sec. 112.20(f)(4), the 
proposed changes to Appendix C are also unnecessary. Therefore, we have 
withdrawn the proposed changes to Appendix C, and it remains unchanged.

Appendix C--Section 2.1--Non-Transportation-Related Facilities With a 
Total Oil Storage Capacity Greater Than or Equal to 42,000 Gallons 
Where Operations Include Over-Water Transfer of Oil

    Background. We have corrected the text of the first sentence in the 
section to correspond with the title, so that it reads ``A non-
transportation-related facility with a total oil storage capacity 
greater than or equal to 42,000 gallons that transfers oil over water 
to or from vessels must submit a response plan to EPA. We added the 
words ``or equal to'' to track rule language found at 
Sec. 112.20(f)(1)(i).

Appendix C--Section 2.4--Proximity to Public Drinking Water Intakes at 
Facilities With a Total Oil Storage Capacity Greater Than or Equal to 1 
Million Gallons

    Background. We have revised the title of this section by reversing 
the order of the words ``Storage'' and ``Oil'' in the heading. We have 
also added the word ``oil'' to the first sentence so that it reads, ``A 
facility with a total oil storage capacity greater than * * *.''

Appendix D--Part A--Section A.2 (Footnote 2)

    Background. We have revised footnote 2 to section A.2 of Part A, 
Appendix D, to reflect the new citation to the SPCC rule's secondary 
containment requirements.

Appendix F--Section 1.2.7--NAICS Codes

    Background. We have revised section 1.2.7 to delete the reference 
to Standard Industry Classification (SIC) codes, and replace it with a 
reference to North American Industry Classification System (NAICS) 
codes. The NAICS was adopted by the United States, Canada, and Mexico 
on January 1, 1997 to replace the SIC codes.

[[Page 47136]]

Appendix F--Section 1.4.3  Analysis of the Potential for an Oil 
Discharge

    Background. We have revised the second and last sentences of this 
section by replacing the word ``spill'' with ``discharge.''

Appendix F--Section 1.7.3 (7)--Containment and Drainage Planning

    Background. We have revised paragraph (7) of section 1.7.3 of 
Appendix F to use the new citation to the SPCC rule's inspection and 
monitoring requirements for drainage.

Appendix F--Section 1.8.1  Facility Self-Inspection

    Background. We have revised section 1.8.1 of Appendix F to use the 
new citation to the SPCC rule's recordkeeping requirements. The 
revision also reflects the three-year record maintenance periods for 
SPCC records and keeps the current five-year period for FRP records.
    Editorial changes and clarifications. ``Tanks'' becomes ``each 
container.''

Appendix F--Section 1.8.1.1--Tank Inspection

    Background. We have revised section 1.8.1.1 of Appendix F to use 
the new citation to the SPCC rule's tank inspection requirements.

Appendix F--Section 1.8.1.3  Secondary Containment Inspection

    Background. We have revised section 1.8.1.1.4 of Appendix F to use 
the new citation to the SPCC rule's secondary containment inspection 
requirements.

Appendix F--Section 1.10  Security

    Background. We have revised section 1.10 of Appendix F to use the 
new citation to the SPCC rule's security requirements.

Appendix F--Section 2.1(6)  General Information

    Background. We have revised paragraph 2.1(6) to refer to NAICS 
codes in place of SIC codes.

Appendix F--Section 3.0  Acronyms

    Background. We have deleted the acronym for SIC and substituted the 
acronym for NAICS.

Appendix F-Attachment F-1  Response Plan Cover Sheet

    Background. We have deleted the reference to SIC and substituted a 
reference to NAICS.

VI. Summary of Supporting Analyses

A. Executive Order 12866--OMB Review

    Under Executive Order 12866, (58 FR 51735, October 4, 1993), the 
Agency must determine whether a regulatory action is ``significant'' 
and therefore subject to Office of Management and Budget (OMB) review 
and the requirements of the Executive Order. The order defines 
``significant regulatory action'' as one that is likely to result in a 
rule that may:
    (1) Have an annual effect on the economy of $100 million or more or 
adversely affect in a material way the economy, a sector of the 
economy, productivity, competition, jobs, the environment, public 
health or safety, or State, local, or tribal governments or 
communities;
    (2) create a serious inconsistency or otherwise interfere with an 
action taken or planned by another agency;
    (3) materially alter the budgetary impact of entitlements, grants, 
user fees, or loan programs or the rights and obligations of recipients 
thereof; or
    (4) raise novel legal or policy issues arising out of legal 
mandates, the President's priorities, or the principles set forth in 
the Executive Order.
    Under the terms of Executive Order 12866, it has been determined 
that this rule is a ``significant regulatory action'' because it raises 
novel legal or policy issues. Such issues include proposed measures 
which would relieve facilities of regulatory mandates and could change 
the manner in which facilities comply with remaining mandates. 
Therefore, this action was submitted to OMB for review. Changes made in 
response to OMB suggestions or recommendations will be documented in 
the public record.
    The reduction in size of the regulated community due to final rule 
revisions will lead to a capital cost savings of approximately $29.47 
million per year. During the first year, regulated facilities will 
experience an increase in total paperwork cost burden of $21.93 million 
due primarily to the need to read the rule. In addition, certain 
facilities will recalculate their storage capacity to exclude 
applicable wastewater treatment systems and, therefore, must amend and 
certify their plans if the storage capacity threshold is still met. In 
certain cases, however, the wastewater treatment system provision in 
section 112.1(b)(6) will result in a facility no longer being subject 
to the any Part 112 requirements. However, during the second year, 
total paperwork cost burden will decrease by about $60.21 million and 
beginning in the third year following the rulemaking, the total 
paperwork cost burden to all regulated facilities will decrease by 
about $45.03 million. The result is an aggregate cost savings of about 
$7.56 million during the first year, $89.69 million during the second 
year, and $74.51 million during subsequent years.

B. Executive Order 12898--Environmental Justice

    Executive Order 12898 requires that each Federal agency make 
achieving environmental justice part of its mission by identifying and 
addressing, as appropriate, disproportionately high and adverse human 
health or environmental effects of its programs, policies, and 
activities on minorities and low-income populations. EPA has determined 
that the regulatory changes in this rule will not have a 
disproportionate impact on minorities and low-income populations.

C. Executive Order 13045--Children's Health

    Executive Order 13045, ``Protection of Children from Environmental 
Health Risks and Safety Risks'' (62 FR 19885, April 23, 1997), applies 
to any rule that: (1) is determined to be ``economically significant'' 
as defined under Executive Order 12866; and, (2) concerns an 
environmental health or safety risk that EPA has reason to believe may 
have a disproportionate effect on children. If the regulatory action 
meets both criteria, the Agency must evaluate the environmental health 
or safety effects of the planned rule on children, and explain why the 
planned regulation is preferable to other potentially effective and 
reasonably feasible alternatives considered by the Agency. EPA 
interprets Executive Order 13045 as applying only to those regulatory 
actions that are based on health or safety risks, such that the 
analysis required under Section 5-501 of the Order has the potential to 
influence the regulation. This final rule is not subject to Executive 
Order 13045 because it is not economically significant as defined in 
Executive Order 12866, and because the Agency does not have reason to 
believe the environmental health or safety risks addressed by this 
action present a disproportionate risk to children. The Agency has no 
data that indicate that the types of risks resulting from oil 
discharges have a disproportionate effect on children, and does not 
have reason to believe that they do so.

D. Executive Order 13175--Consultation and Coordination with Indian 
Tribal Governments

    On November 6, 2000, the President issued Executive Order 13175 (65 
FR 67249) entitled, ``Consultation and Coordination with Indian Tribal 
Governments.'' Executive Order 13175 took effect on January 6, 2001, 
and revokes Executive Order 13084 (Tribal

[[Page 47137]]

Consultation) as of that date. EPA developed this final rule, however, 
under the period when EO 13084 was in effect; thus, EPA addressed 
tribal considerations under EO 13084.
    Today's rule does not significantly or uniquely affect communities 
of Indian tribal governments. Overall, the rule significantly reduces 
the regulatory burden, and the few burden increases in the rule do not 
uniquely affect Indian tribal governments.
    Nevertheless, we consulted with a representative organization of 
tribal groups, the Tribal Association on Solid Waste and Emergency 
Response. That organization did not provide us with any comments.

E. Executive Order 13132--Federalism

    Executive Order 13132, entitled ``Federalism'' (64 FR 43255, August 
10, 1999), requires EPA to develop an accountable process to ensure 
``meaningful and timely input by State and local officials in the 
development of regulatory policies that have federalism implications.'' 
``Policies that have federalism implications'' is defined in the 
Executive Order to include regulations that have ``substantial direct 
effects on the States, on the relationship between the national 
government and the States, or on the distribution of power and 
responsibilities among the various levels of government.''
    This final rule does not have federalism implications. It will not 
have substantial direct effects on the States, on the relationship 
between the national government and the States, or on the distribution 
of power and responsibilities among the various levels of government, 
as specified in Executive Order 13132. Under CWA section 311(o), EPA 
believes that States are free to impose additional requirements, 
including more stringent requirements, relating to the prevention of 
oil discharges to navigable waters. In proposing modifications to the 
SPCC rule, EPA encouraged States to supplement the federal SPCC program 
and recognized that some States have more stringent requirements. 56 FR 
54612 (Oct. 22, 1991). This rule does not preempt state law or 
regulations. Thus, Executive Order 13132 does not apply to this rule.

F. Executive Order 13211--Energy Effects

    This rule is not a ``significant energy action'' as defined in 
Executive Order 13211, ``Actions Concerning Regulations That 
Significantly Affect Energy Supply, Distribution, or Use'' (66 FR 
28355, May 22, 2001) because it is not likely to have a significant 
adverse effect on the supply, distribution, or use of energy. The 
overall effect of the rule is to decrease the regulatory burden on 
facility owners or operators subject to its provisions.

G. Regulatory Flexibility Act (R.F.A.) as amended by the Small Business 
Regulatory Enforcement Fairness Act of 1996 (SBREFA), 5 U.S.C. 601 et 
seq.

    The R.F.A. generally requires an agency to prepare a regulatory 
flexibility analysis of any rule subject to notice and comment 
rulemaking requirements under the Administrative Procedure Act or any 
other statute unless the agency certifies that the rule will not have a 
significant economic impact on a substantial number of small entities. 
Small entities include small businesses, small organizations, and small 
governmental jurisdictions.
    For purposes of assessing the impacts of today's rule on small 
entities, small entity is defined as: (1) A small business as defined 
in the Small Business Administration's (SBA) regulations at 13 CFR 
121.201--the SBA defines small businesses by category of business using 
North American Industry Classification System (NAICS) codes, and in the 
case of farms and production facilities, which constitute a large 
percentage of the facilities affected by this rule, generally defines 
small businesses as having less than $500,000 in revenues or 500 
employees, respectively; (2) a small governmental jurisdiction that is 
a government of a city, county, town, school district or special 
district with a population of less than 50,000; and (3) a small 
organization that is any not-for-profit enterprise which is 
independently owned and operated and is not dominant in its field.
    In determining whether a rule has a significant economic impact on 
a substantial number of small entities, the impact of concern is any 
significant adverse economic impact on small entities, since the 
primary purpose of the regulatory flexibility analyses is to identify 
and address regulatory alternatives ``which minimize any significant 
economic impact of the proposed rule on small entities.'' 5 U.S.C. 603 
and 604. Thus, an agency may certify that a rule will not have a 
significant economic impact on a substantial number of small entities 
if the rule relieves regulatory burden, or otherwise has a positive 
economic effect on all of the small entities subject to the rule. This 
rule will significantly reduce regulatory burden on all facilities, 
particularly small facilities. For example, the rule exempts 
approximately 55,000 facilities from its scope. Approximately 41,300 of 
those facilities are small facilities, and of those, nearly 27,700 are 
small farms. This rulemaking will increase information collection 
burden for most facilities in the first year by approximately 0.75 
million hours due principally to the estimated burden each facility 
will incur to read and understand the changes that we are making to the 
rule. However, the rule will also reduce the overall annual information 
collection burden by nearly 1.59 million hours a year in the second 
year and over 1.18 million hours a year in the third year of the 
information collection request, much of that for the small facilities 
that make up the large majority of our regulated universe. Further, the 
rule will reduce costs for both existing and new facilities.
    Information collection and other provisions in the final rule that 
affect capital costs are expected to yield cost savings of about $7.56 
million during the first year, $89.69 million during the second year 
and $74.51 million during subsequent years. The rule also gives all 
facilities greater flexibility in recordkeeping and other paperwork 
requirements. Finally, Sec. 112.7(a)(2) of the rule gives small 
businesses and all other facilities the flexibility to use alternative 
methods to comply with the requirements of the rule if the facility 
explains its rationale for nonconformance and provides equivalent 
environmental protection. We have therefore concluded that today's 
final rule will relieve regulatory burden for all small entities.
    After considering the economic impacts of today's final rule on 
small entities, I certify that this action will not have a significant 
economic impact on a substantial number of small entities.

H. Unfunded Mandates Reform Act

    Title II of the Unfunded Mandates Reform Act of 1995 (UMRA), Pub. 
L. 104-4, establishes requirements for Federal agencies to assess the 
effects of their regulatory actions on State, local, and tribal 
governments and the private sector. Under section 202 of UMRA, EPA 
generally must prepare a written statement, including a cost-benefit 
analysis, for proposed and final rules with ``Federal mandates'' that 
may result in expenditures to State, local, and tribal governments, in 
the aggregate, or to the private sector, of $100 million or more in any 
one year. Before promulgating an EPA rule for which a written statement 
is needed, section 205 of UMRA generally requires EPA to identify and 
consider a reasonable number of regulatory alternatives and adopt the 
least costly, most cost-effective or least burdensome alternative

[[Page 47138]]

that achieves the objectives of the rule. The provisions of section 205 
do not apply when they are inconsistent with applicable law. Moreover, 
section 205 allows EPA to adopt an alternative other than the least 
costly, most-effective or least burdensome alternative if the 
Administrator publishes with the final rule an explanation why that 
alternative was not adopted.
    Before EPA establishes any regulatory requirements that may 
significantly or uniquely affect small governments, including tribal 
governments, it must have developed under section 203 of UMRA a small 
government agency plan. The plan must provide for notifying potentially 
affected small governments, enabling officials of affected small 
governments to have meaningful and timely input in the development of 
EPA regulatory proposals with significant Federal intergovernmental 
mandates, and informing, educating, and advising small governments on 
compliance with the regulatory requirements.
    EPA has determined that this rule does not contain a Federal 
mandate that may result in expenditures of $100 million or more for 
State, local, and tribal governments, in the aggregate, or the private 
sector in any one year. Overall, the rule reduces burden and costs on 
all facilities. After the first and second year, the rule is expected 
to reduce the information collection burden by over 1.3 million hours 
annually.
    Approximately 55,000 facilities will no longer be subject to the 
SPCC rule. Of these facilities, EPA estimates that approximately 3,500 
existing facilities will no longer be required to maintain SPCC plans, 
due to the exemption for certain wastewater treatment systems. Other 
revisions are expected to exempt approximately 51,400 additional 
facilities 39,623 small facilities (including 27,700 small farms). The 
exemption for completely buried containers will result in approximately 
14,000 facilities no longer subject to the rule, and 37,000 more 
facilities with some partial information collection reduction. Further, 
EPA estimates Information collection and capital costs are expected to 
decrease by over $74.25 million a year in the third year of the SPCC 
information collection request. In addition to these SPCC-related 
impacts, this rulemaking is estimated to result in cost savings for as 
many as 35 facilities that are expected to no longer require facility 
response plans due to the wastewater treatment system exemption. The 
result of the changes to the scope of the FRP information collection 
requirements is a cost savings of approximately $0.23 million per year. 
The rule also gives all facilities greater flexibility in recordkeeping 
and other paperwork requirements. Finally, Sec. 112.7(a)(2) of the rule 
gives small businesses and all other facilities the flexibility to use 
alternate methods to comply with the requirements of the rule if the 
facility explains its rationale for nonconformance and describes its 
method of equivalent environmental protection. Thus, today's rule is 
not subject to the requirements of sections 202 and 205 of the UMRA.
    In developing this rule, EPA nevertheless consulted with 
representative organizations of State, local, and tribal governments. 
The representative organizations were the Environmental Council of the 
States, the National Association of Counties, and the Tribal 
Association on Solid Waste and Emergency Response. None of those 
organizations provided us with any comments. However, numerous States 
and local governments did comment on the rule proposals in all three 
proposed rulemakings. Those commenters submitted a wide variety of 
comments. EPA responses to those comments may be found in this document 
and in the Comment Response Documents.
    EPA has determined that this rule contains no regulatory 
requirements that might significantly or uniquely affect small 
governments. As explained above, the overall effect of the rule will be 
to reduce burden and costs for regulated facilities, including small 
governments that are subject to the rule.

I. Paperwork Reduction Act

    The Office of Management and Budget (OMB) has approved the 
information collection requirements contained in this rule under the 
provisions of the Paperwork Reduction Act, 44 U.S.C. 3501 et seq. and 
has assigned OMB control number 2050-0021.
    EPA does not collect the information required by SPCC regulation on 
a routine basis. SPCC Plans ordinarily need not be submitted to EPA, 
but must generally be maintained at the facility. Preparation, 
implementation, and maintenance of an SPCC Plan by the facility helps 
prevent oil discharges, and mitigates the environmental damage caused 
by such discharges. Therefore, the primary user of the data is the 
facility. While EPA may, from time to time, request information under 
these regulations, such requests are not routine.
    Although the facility is the primary data user, EPA also uses the 
data in certain situations. EPA primarily uses SPCC Plan data to ensure 
that facilities comply with the regulation. This includes design and 
operation specifications, and inspection requirements. EPA reviews SPCC 
Plans: (1) when it requests a facility to submit a Plan after certain 
oil discharges or to evaluate an extension request; and, (2) as part of 
EPA's inspection program. Note that the final rule eliminates the 
previous requirement to submit the entire Plan after certain 
discharges, and merely retains the requirement that it be maintained at 
the facility unless EPA requests a copy. State and local governments 
also use the data, which are not necessarily available elsewhere and 
can greatly assist local emergency preparedness efforts. Preparation of 
the information for affected facilities is required under section 
311(j)(1) of the Act as implemented by 40 CFR part 112.
    In the absence of this final rulemaking, EPA estimates that 469,274 
facilities would have been subject to the rule in the first year and 
would have already prepared SPCC Plans. In addition, EPA estimates that 
approximately 4,700 new facilities would have become subject to the 
requirements of the rule annually. EPA also estimates that, in the 
absence of this rulemaking, the average annual public reporting and 
recordkeeping burden for this collection of information for existing 
and newly regulated facilities would have ranged between 4.9 to 13.8 
hours and 39.4 to 100.4 hours, respectively, depending on facility 
characteristics (e.g., storage capacity).
    Through this rulemaking, we expect to reduce both the number of 
regulated facilities, as well as the average annual burden for 
facilities that remain regulated. The number of regulated facilities 
will be reduced by approximately 55,000. The average annual public 
reporting for facilities already regulated by the Oil Pollution 
Prevention regulation is estimated to range between 8.6 and 12.2 hours, 
while the burden for newly regulated facilities is estimated to range 
between 35.1 and 65.2 hours as a result of this rulemaking. These 
average annual burden estimates take into account the varied 
frequencies of response for individual facilities according to 
characteristics specific to those facilities, including the frequency 
of oil discharges and facility modification, but exclude the 
anticipated burden facilities may incur in the first year to read and 
understand the changes we are making to the rule.
    Under the final rule, an estimated 419,033 existing and newly 
regulated facilities will be subject to the SPCC information collection 
requirements of this rule during the first year of the information 
collection period. The net annualized capital and start-up costs for

[[Page 47139]]

the SPCC information collection portion of the rule average $740,000 
and net annualized labor and operation and maintenance costs are 
estimated to be $93.00 million for all of these facilities combined.
    The information collection burden of the SPCC rule prior to this 
rulemaking averaged 2,828,150 hours per year. Under this final rule, 
the annual average burden over the next three-year ICR period is 
estimated to be 2,208,701 hours, resulting in a 22 percent average 
reduction. This rulemaking will increase burden for most facilities in 
the first year (totaling approximately 3.6 million hours) due 
principally to the estimated burden each facility will incur to read 
and understand the changes that we are making to the rule. The first-
year burden also includes the additional need for certain facilities to 
amend and certify their SPCC plans to exclude wastewater treatment 
volumes from their oil storage capacity. Second year burden is expected 
to total approximately 1.3 million hours. In subsequent years, we 
estimate that the overall burden will be approximately 1.7 million 
hours annually, representing a nearly 40 percent reduction versus the 
average annual burden from the previous information collection period. 
Burden means the total time, effort, or financial resources expended by 
persons to generate, maintain, retain, or disclose or provide 
information to or for a Federal agency. This includes the time needed 
to review instructions; develop, acquire, install, and utilize 
technology and systems for the purposes of collecting, validating, and 
verifying information, processing and maintaining information, and 
disclosing and providing information; adjust the existing ways to 
comply with any previously applicable instructions and requirements; 
train personnel to be able to respond to a collection of information; 
search data sources; complete and review the collection of information; 
and transmit or otherwise disclose the information.
    In addition to reducing the information collection burden of SPCC 
facilities, this final rule also affects the number of facilities that 
require an FRP. The FRP rule (40 CFR 112.20-21) requires that owners or 
operators of facilities that could cause ``substantial harm'' to the 
environment by discharging oil into navigable waters or adjoining 
shorelines prepare plans for responding, to the maximum extent 
practicable, to a worst case discharge of oil, to a substantial threat 
of such a discharge, and, as appropriate, to discharges smaller than 
worst case discharges. All facilities subject to this requirement must 
submit their plans to EPA. In turn, we review and approve plans 
submitted by facilities identified as ``significant and substantial 
harm'' to the environment from oil discharges. Other facilities are not 
required to prepare FRPs but are required to document their 
determination that they do not meet the ``substantial harm'' criteria.
    Prior to this rulemaking, EPA estimated that it requires between 99 
and 132 hours for facility personnel in a large facility (i.e., total 
storage capacity greater than 1 million gallons) and between 26 and 46 
hours for personnel in a medium facility (i.e., total storage capacity 
greater than 42,000 gallons and less than or equal to 1 million 
gallons) to comply with the annual, subsequent-year reporting and 
recordkeeping requirements of the FRP rule. We have also estimated that 
prior to this rulemaking newly regulated large and medium facilities 
will require between 253 and 293 hours and 109 and 142 hours, 
respectively, to prepare a plan in the first year. In the absence of 
this rulemaking, EPA estimates that the total number FRP facilities 
affected in the first year would have been 6,000 existing and 70 new 
facilities. Through this rulemaking the estimated number of facilities 
required to maintain FRPs is reduced to 5,965 and the number of new 
facilities that will be required to prepare and submit FRP plans is 
reduced to 64 facilities. This reduction in the number of facilities 
required to prepare, submit, and/or maintain an FRP would result in an 
average annual information collection burden reduction of 8,513 hours a 
year (624,252 to 615,739 hours).
    An Agency may not conduct or sponsor, and a person is not required 
to respond to a collection of information unless it displays a 
currently valid OMB control number. The OMB control numbers for EPA's 
regulations are listed in 40 CFR part 9 and 48 CFR Chapter 15. EPA is 
amending the table in 40 CFR part 9 of currently approved ICR control 
numbers issued by OMB for various regulations to list the information 
requirements contained in this final rule.

J. National Technology Transfer and Advancement Act

    As noted in the December 7, 1997, proposed rule, section 12(d) of 
the National Technology Transfer and Advancement Act of 1995 
(``NTTAA''). Pub. L. 104-113, section 12(d) (15 U.S.C. 272 note) 
directs EPA to use voluntary consensus standards in its regulatory 
activities unless to do so would be inconsistent with applicable law or 
otherwise impractical. Voluntary consensus standards are technical 
standards such as materials specifications, test methods, sampling 
procedures, and business practices that are developed or adopted by 
voluntary consensus standards bodies. The NTTAA directs EPA to provide 
Congress, through OMB, explanations when the Agency decides not to use 
available and applicable voluntary consensus standards.
    This rulemaking involves technical standards. Throughout today's 
preamble, EPA has emphasized that owners or operators of facilities 
should use applicable industry standards in performing tests, 
inspections, and in monitoring. Section 112.3(d) provides that a 
Professional Engineer must certify that the SPCC Plan has been prepared 
in accordance with good engineering practice, including consideration 
of applicable industry standards. We are providing examples of specific 
standards in today's preamble. However, due to the wide variety of 
facilities the rule involves, few standards would be applicable to all 
regulated facilities. Also, those standards change over time. 
Therefore, we are not incorporating those standards into rule text.

K. Congressional Review Act

    The Congressional Review Act, 5 U.S.C. 801 et seq., as added by the 
Small Business Regulatory Enforcement Fairness Act of 1996, generally 
provides that before a rule may take effect, the agency promulgating 
the rule must submit a rule report, which includes a copy of the rule, 
to each House of Congress and to the Comptroller General of the United 
States. EPA has submitted a report containing this rule and other 
required information to the U.S. Senate, the U.S. House of 
Representatives, and the Comptroller General of the United States prior 
to publication of the rule in the Federal Register. This action is not 
a ``major rule'' as defined by 5 U.S.C. 804(2). This rule will be 
effective August 16, 2002.

List of Subjects in 40 CFR Part 112

    Environmental protection, Fire prevention, Flammable materials, 
Materials handling and storage, Oil pollution, Oil spill prevention, 
Oil spill response, Penalties, Petroleum, Reporting and recordkeeping 
requirements, Tanks, Water pollution control, Water resources.

    Dated: June 28, 2002.
Christine Todd Whitman,
Administrator.

    For the reasons set out in the preamble, title 40 CFR, chapter I, 
part

[[Page 47140]]

112 of the Code of Federal Regulations, is amended as follows:

PART 112--OIL POLLUTION PREVENTION

    1. The authority for part 112 continues to read as follows:

    Authority: 33 U.S.C. 1251 et seq.; 33 U.S.C 2720; E.O. 12777 
(October 18, 1991), 3 CFR, 1991 Comp., p. 351.


    2. Part 112 is amended by designating Secs. 112.1 through 112.7 as 
subpart A, adding a subpart heading and revising newly designated 
subpart A to read as follows:
Subpart A--Applicability, Definitions, and General Requirements For All 
Facilities and All Types of Oils
Sec.
112.1  General applicability.
112.2  Definitions.
112.3  Requirement to prepare and implement a Spill Prevention, 
Control, and Countermeasure Plan.
112.4  Amendment of Spill Prevention, Control, and Countermeasure 
Plan by Regional Administrator.
112.5  Amendment of Spill Prevention, Control, and Countermeasure 
Plan by owners or operators.
112.6  [Reserved].
112.7  General requirements for Spill Prevention, Control, and 
Countermeasure Plans.

Subpart A--Applicability, Definitions, and General Requirements for 
All Facilities and All Types of Oils


Sec. 112.1  General applicability.

    (a)(1) This part establishes procedures, methods, equipment, and 
other requirements to prevent the discharge of oil from non-
transportation-related onshore and offshore facilities into or upon the 
navigable waters of the United States or adjoining shorelines, or into 
or upon the waters of the contiguous zone, or in connection with 
activities under the Outer Continental Shelf Lands Act or the Deepwater 
Port Act of 1974, or that may affect natural resources belonging to, 
appertaining to, or under the exclusive management authority of the 
United States (including resources under the Magnuson Fishery 
Conservation and Management Act).
    (2) As used in this part, words in the singular also include the 
plural and words in the masculine gender also include the feminine and 
vice versa, as the case may require.
    (b) Except as provided in paragraph (d) of this section, this part 
applies to any owner or operator of a non-transportation-related 
onshore or offshore facility engaged in drilling, producing, gathering, 
storing, processing, refining, transferring, distributing, using, or 
consuming oil and oil products, which due to its location, could 
reasonably be expected to discharge oil in quantities that may be 
harmful, as described in part 110 of this chapter, into or upon the 
navigable waters of the United States or adjoining shorelines, or into 
or upon the waters of the contiguous zone, or in connection with 
activities under the Outer Continental Shelf Lands Act or the Deepwater 
Port Act of 1974, or that may affect natural resources belonging to, 
appertaining to, or under the exclusive management authority of the 
United States (including resources under the Magnuson Fishery 
Conservation and Management Act) that has oil in:
    (1) Any aboveground container;
    (2) Any completely buried tank as defined in Sec. 112.2;
    (3) Any container that is used for standby storage, for seasonal 
storage, or for temporary storage, or not otherwise ``permanently 
closed'' as defined in Sec. 112.2;
    (4) Any ``bunkered tank'' or ``partially buried tank'' as defined 
in Sec. 112.2, or any container in a vault, each of which is considered 
an aboveground storage container for purposes of this part.
    (c) As provided in section 313 of the Clean Water Act (CWA), 
departments, agencies, and instrumentalities of the Federal government 
are subject to this part to the same extent as any person.
    (d) Except as provided in paragraph (f) of this section, this part 
does not apply to:
    (1) The owner or operator of any facility, equipment, or operation 
that is not subject to the jurisdiction of the Environmental Protection 
Agency (EPA) under section 311(j)(1)(C) of the CWA, as follows:
    (i) Any onshore or offshore facility, that due to its location, 
could not reasonably be expected to have a discharge as described in 
paragraph (b) of this section. This determination must be based solely 
upon consideration of the geographical and location aspects of the 
facility (such as proximity to navigable waters or adjoining 
shorelines, land contour, drainage, etc.) and must exclude 
consideration of manmade features such as dikes, equipment or other 
structures, which may serve to restrain, hinder, contain, or otherwise 
prevent a discharge as described in paragraph (b) of this section.
    (ii) Any equipment, or operation of a vessel or transportation-
related onshore or offshore facility which is subject to the authority 
and control of the U.S. Department of Transportation, as defined in the 
Memorandum of Understanding between the Secretary of Transportation and 
the Administrator of EPA, dated November 24, 1971 (Appendix A of this 
part).
    (iii) Any equipment, or operation of a vessel or onshore or 
offshore facility which is subject to the authority and control of the 
U.S. Department of Transportation or the U.S. Department of the 
Interior, as defined in the Memorandum of Understanding between the 
Secretary of Transportation, the Secretary of the Interior, and the 
Administrator of EPA, dated November 8, 1993 (Appendix B of this part).
    (2) Any facility which, although otherwise subject to the 
jurisdiction of EPA, meets both of the following requirements:
    (i) The completely buried storage capacity of the facility is 
42,000 gallons or less of oil. For purposes of this exemption, the 
completely buried storage capacity of a facility excludes the capacity 
of a completely buried tank, as defined in Sec. 112.2, and connected 
underground piping, underground ancillary equipment, and containment 
systems, that is currently subject to all of the technical requirements 
of part 280 of this chapter or all of the technical requirements of a 
State program approved under part 281 of this chapter. The completely 
buried storage capacity of a facility also excludes the capacity of a 
container that is ``permanently closed,'' as defined in Sec. 112.2.
    (ii) The aggregate aboveground storage capacity of the facility is 
1,320 gallons or less of oil. For purposes of this exemption, only 
containers of oil with a capacity of 55 gallons or greater are counted. 
The aggregate aboveground storage capacity of a facility excludes the 
capacity of a container that is ``permanently closed,'' as defined in 
Sec. 112.2.
    (3) Any offshore oil drilling, production, or workover facility 
that is subject to the notices and regulations of the Minerals 
Management Service, as specified in the Memorandum of Understanding 
between the Secretary of Transportation, the Secretary of the Interior, 
and the Administrator of EPA, dated November 8, 1993 (Appendix B of 
this part).
    (4) Any completely buried storage tank, as defined in Sec. 112.2, 
and connected underground piping, underground ancillary equipment, and 
containment systems, at any facility, that is subject to all of the 
technical requirements of part 280 of this chapter or a State program 
approved under part 281 of this chapter, except that such a tank must 
be marked on the facility diagram as provided in Sec. 112.7(a)(3), if

[[Page 47141]]

the facility is otherwise subject to this part.
    (5) Any container with a storage capacity of less than 55 gallons 
of oil.
    (6) Any facility or part thereof used exclusively for wastewater 
treatment and not used to satisfy any requirement of this part. The 
production, recovery, or recycling of oil is not wastewater treatment 
for purposes of this paragraph.
    (e) This part establishes requirements for the preparation and 
implementation of Spill Prevention, Control, and Countermeasure (SPCC) 
Plans. SPCC Plans are designed to complement existing laws, 
regulations, rules, standards, policies, and procedures pertaining to 
safety standards, fire prevention, and pollution prevention rules. The 
purpose of an SPCC Plan is to form a comprehensive Federal/State spill 
prevention program that minimizes the potential for discharges. The 
SPCC Plan must address all relevant spill prevention, control, and 
countermeasures necessary at the specific facility. Compliance with 
this part does not in any way relieve the owner or operator of an 
onshore or an offshore facility from compliance with other Federal, 
State, or local laws.
    (f) Notwithstanding paragraph (d) of this section, the Regional 
Administrator may require that the owner or operator of any facility 
subject to the jurisdiction of EPA under section 311(j) of the CWA 
prepare and implement an SPCC Plan, or any applicable part, to carry 
out the purposes of the CWA.
    (1) Following a preliminary determination, the Regional 
Administrator must provide a written notice to the owner or operator 
stating the reasons why he must prepare an SPCC Plan, or applicable 
part. The Regional Administrator must send such notice to the owner or 
operator by certified mail or by personal delivery. If the owner or 
operator is a corporation, the Regional Administrator must also mail a 
copy of such notice to the registered agent, if any and if known, of 
the corporation in the State where the facility is located.
    (2) Within 30 days of receipt of such written notice, the owner or 
operator may provide information and data and may consult with the 
Agency about the need to prepare an SPCC Plan, or applicable part.
    (3) Within 30 days following the time under paragraph (b)(2) of 
this section within which the owner or operator may provide information 
and data and consult with the Agency about the need to prepare an SPCC 
Plan, or applicable part, the Regional Administrator must make a final 
determination regarding whether the owner or operator is required to 
prepare and implement an SPCC Plan, or applicable part. The Regional 
Administrator must send the final determination to the owner or 
operator by certified mail or by personal delivery. If the owner or 
operator is a corporation, the Regional Administrator must also mail a 
copy of the final determination to the registered agent, if any and if 
known, of the corporation in the State where the facility is located.
    (4) If the Regional Administrator makes a final determination that 
an SPCC Plan, or applicable part, is necessary, the owner or operator 
must prepare the Plan, or applicable part, within six months of that 
final determination and implement the Plan, or applicable part, as soon 
as possible, but not later than one year after the Regional 
Administrator has made a final determination.
    (5) The owner or operator may appeal a final determination made by 
the Regional Administrator requiring preparation and implementation of 
an SPCC Plan, or applicable part, under this paragraph. The owner or 
operator must make the appeal to the Administrator of EPA within 30 
days of receipt of the final determination under paragraph (b)(3) of 
this section from the Regional Administrator requiring preparation and/
or implementation of an SPCC Plan, or applicable part. The owner or 
operator must send a complete copy of the appeal to the Regional 
Administrator at the time he makes the appeal to the Administrator. The 
appeal must contain a clear and concise statement of the issues and 
points of fact in the case. In the appeal, the owner or operator may 
also provide additional information. The additional information may be 
from any person. The Administrator may request additional information 
from the owner or operator. The Administrator must render a decision 
within 60 days of receiving the appeal or additional information 
submitted by the owner or operator and must serve the owner or operator 
with the decision made in the appeal in the manner described in 
paragraph (f)(1) of this section.


Sec. 112.2  Definitions.

    For the purposes of this part:
    Adverse weather means weather conditions that make it difficult for 
response equipment and personnel to clean up or remove spilled oil, and 
that must be considered when identifying response systems and equipment 
in a response plan for the applicable operating environment. Factors to 
consider include significant wave height as specified in Appendix E to 
this part (as appropriate), ice conditions, temperatures, weather-
related visibility, and currents within the area in which the systems 
or equipment is intended to function.
    Alteration means any work on a container involving cutting, 
burning, welding, or heating operations that changes the physical 
dimensions or configuration of the container.
    Animal fat means a non-petroleum oil, fat, or grease of animal, 
fish, or marine mammal origin.
    Breakout tank means a container used to relieve surges in an oil 
pipeline system or to receive and store oil transported by a pipeline 
for reinjection and continued transportation by pipeline.
    Bulk storage container means any container used to store oil. These 
containers are used for purposes including, but not limited to, the 
storage of oil prior to use, while being used, or prior to further 
distribution in commerce. Oil-filled electrical, operating, or 
manufacturing equipment is not a bulk storage container.
    Bunkered tank means a container constructed or placed in the ground 
by cutting the earth and re-covering the container in a manner that 
breaks the surrounding natural grade, or that lies above grade, and is 
covered with earth, sand, gravel, asphalt, or other material. A 
bunkered tank is considered an aboveground storage container for 
purposes of this part.
    Completely buried tank means any container completely below grade 
and covered with earth, sand, gravel, asphalt, or other material. 
Containers in vaults, bunkered tanks, or partially buried tanks are 
considered aboveground storage containers for purposes of this part.
    Complex means a facility possessing a combination of 
transportation-related and non-transportation-related components that 
is subject to the jurisdiction of more than one Federal agency under 
section 311(j) of the CWA.
    Contiguous zone means the zone established by the United States 
under Article 24 of the Convention of the Territorial Sea and 
Contiguous Zone, that is contiguous to the territorial sea and that 
extends nine miles seaward from the outer limit of the territorial 
area.
    Contract or other approved means means:
    (1) A written contractual agreement with an oil spill removal 
organization that identifies and ensures the availability of the 
necessary personnel and equipment within appropriate response times; 
and/or

[[Page 47142]]

    (2) A written certification by the owner or operator that the 
necessary personnel and equipment resources, owned or operated by the 
facility owner or operator, are available to respond to a discharge 
within appropriate response times; and/or
    (3) Active membership in a local or regional oil spill removal 
organization that has identified and ensures adequate access through 
such membership to necessary personnel and equipment to respond to a 
discharge within appropriate response times in the specified geographic 
area; and/or
    (4) Any other specific arrangement approved by the Regional 
Administrator upon request of the owner or operator.
    Discharge includes, but is not limited to, any spilling, leaking, 
pumping, pouring, emitting, emptying, or dumping of oil, but excludes 
discharges in compliance with a permit under section 402 of the CWA; 
discharges resulting from circumstances identified, reviewed, and made 
a part of the public record with respect to a permit issued or modified 
under section 402 of the CWA, and subject to a condition in such 
permit; or continuous or anticipated intermittent discharges from a 
point source, identified in a permit or permit application under 
section 402 of the CWA, that are caused by events occurring within the 
scope of relevant operating or treatment systems. For purposes of this 
part, the term discharge shall not include any discharge of oil that is 
authorized by a permit issued under section 13 of the River and Harbor 
Act of 1899 (33 U.S.C. 407).
    Facility means any mobile or fixed, onshore or offshore building, 
structure, installation, equipment, pipe, or pipeline (other than a 
vessel or a public vessel) used in oil well drilling operations, oil 
production, oil refining, oil storage, oil gathering, oil processing, 
oil transfer, oil distribution, and waste treatment, or in which oil is 
used, as described in Appendix A to this part. The boundaries of a 
facility depend on several site-specific factors, including, but not 
limited to, the ownership or operation of buildings, structures, and 
equipment on the same site and the types of activity at the site.
    Fish and wildlife and sensitive environments means areas that may 
be identified by their legal designation or by evaluations of Area 
Committees (for planning) or members of the Federal On-Scene 
Coordinator's spill response structure (during responses). These areas 
may include wetlands, National and State parks, critical habitats for 
endangered or threatened species, wilderness and natural resource 
areas, marine sanctuaries and estuarine reserves, conservation areas, 
preserves, wildlife areas, wildlife refuges, wild and scenic rivers, 
recreational areas, national forests, Federal and State lands that are 
research national areas, heritage program areas, land trust areas, and 
historical and archaeological sites and parks. These areas may also 
include unique habitats such as aquaculture sites and agricultural 
surface water intakes, bird nesting areas, critical biological resource 
areas, designated migratory routes, and designated seasonal habitats.
    Injury means a measurable adverse change, either long- or short-
term, in the chemical or physical quality or the viability of a natural 
resource resulting either directly or indirectly from exposure to a 
discharge, or exposure to a product of reactions resulting from a 
discharge.
    Maximum extent practicable means within the limitations used to 
determine oil spill planning resources and response times for on-water 
recovery, shoreline protection, and cleanup for worst case discharges 
from onshore non-transportation-related facilities in adverse weather. 
It includes the planned capability to respond to a worst case discharge 
in adverse weather, as contained in a response plan that meets the 
requirements in Sec. 112.20 or in a specific plan approved by the 
Regional Administrator.
    Navigable waters means the waters of the United States, including 
the territorial seas.
    (1) The term includes:
    (i) All waters that are currently used, were used in the past, or 
may be susceptible to use in interstate or foreign commerce, including 
all waters subject to the ebb and flow of the tide;
    (ii) All interstate waters, including interstate wetlands;
    (iii) All other waters such as intrastate lakes, rivers, streams 
(including intermittent streams), mudflats, sandflats, wetlands, 
sloughs, prairie potholes, wet meadows, playa lakes, or natural ponds, 
the use, degradation, or destruction of which could affect interstate 
or foreign commerce including any such waters:
    (A) That are or could be used by interstate or foreign travelers 
for recreational or other purposes; or
    (B) From which fish or shellfish are or could be taken and sold in 
interstate or foreign commerce; or,
    (C) That are or could be used for industrial purposes by industries 
in interstate commerce;
    (iv) All impoundments of waters otherwise defined as waters of the 
United States under this section;
    (v) Tributaries of waters identified in paragraphs (1)(i) through 
(iv) of this definition;
    (vi) The territorial sea; and
    (vii) Wetlands adjacent to waters (other than waters that are 
themselves wetlands) identified in paragraph (1) of this definition.
    (2) Waste treatment systems, including treatment ponds or lagoons 
designed to meet the requirements of the CWA (other than cooling ponds 
which also meet the criteria of this definition) are not waters of the 
United States. Navigable waters do not include prior converted 
cropland. Notwithstanding the determination of an area's status as 
prior converted cropland by any other Federal agency, for the purposes 
of the CWA, the final authority regarding CWA jurisdiction remains with 
EPA.
    Non-petroleum oil means oil of any kind that is not petroleum-
based, including but not limited to: Fats, oils, and greases of animal, 
fish, or marine mammal origin; and vegetable oils, including oils from 
seeds, nuts, fruits, and kernels.
    Offshore facility means any facility of any kind (other than a 
vessel or public vessel) located in, on, or under any of the navigable 
waters of the United States, and any facility of any kind that is 
subject to the jurisdiction of the United States and is located in, on, 
or under any other waters.
    Oil means oil of any kind or in any form, including, but not 
limited to: fats, oils, or greases of animal, fish, or marine mammal 
origin; vegetable oils, including oils from seeds, nuts, fruits, or 
kernels; and, other oils and greases, including petroleum, fuel oil, 
sludge, synthetic oils, mineral oils, oil refuse, or oil mixed with 
wastes other than dredged spoil.
    Oil Spill Removal Organization means an entity that provides oil 
spill response resources, and includes any for-profit or not-for-profit 
contractor, cooperative, or in-house response resources that have been 
established in a geographic area to provide required response 
resources.
    Onshore facility means any facility of any kind located in, on, or 
under any land within the United States, other than submerged lands.
    Owner or operator means any person owning or operating an onshore 
facility or an offshore facility, and in the case of any abandoned 
offshore facility, the person who owned or operated or maintained the 
facility immediately prior to such abandonment.
    Partially buried tank means a storage container that is partially 
inserted or constructed in the ground, but not entirely below grade, 
and not

[[Page 47143]]

completely covered with earth, sand, gravel, asphalt, or other 
material. A partially buried tank is considered an aboveground storage 
container for purposes of this part.
    Permanently closed means any container or facility for which:
    (1) All liquid and sludge has been removed from each container and 
connecting line; and
    (2) All connecting lines and piping have been disconnected from the 
container and blanked off, all valves (except for ventilation valves) 
have been closed and locked, and conspicuous signs have been posted on 
each container stating that it is a permanently closed container and 
noting the date of closure.
    Person includes an individual, firm, corporation, association, or 
partnership.
    Petroleum oil means petroleum in any form, including but not 
limited to crude oil, fuel oil, mineral oil, sludge, oil refuse, and 
refined products.
    Production facility means all structures (including but not limited 
to wells, platforms, or storage facilities), piping (including but not 
limited to flowlines or 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, or associated storage or measurement, and located in a single 
geographical oil or gas field operated by a single operator.
    Regional Administrator means the Regional Administrator of the 
Environmental Protection Agency, in and for the Region in which the 
facility is located.
    Repair means any work necessary to maintain or restore a container 
to a condition suitable for safe operation, other than that necessary 
for ordinary, day-to-day maintenance to maintain the functional 
integrity of the container and that does not weaken the container.
    Spill Prevention, Control, and Countermeasure Plan; SPCC Plan, or 
Plan means the document required by Sec. 112.3 that details the 
equipment, workforce, procedures, and steps to prevent, control, and 
provide adequate countermeasures to a discharge.
    Storage capacity of a container means the shell capacity of the 
container.
    Transportation-related and non-transportation-related, as applied 
to an onshore or offshore facility, are defined in the Memorandum of 
Understanding between the Secretary of Transportation and the 
Administrator of the Environmental Protection Agency, dated November 
24, 1971, (Appendix A of this part).
    United States means the States, the District of Columbia, the 
Commonwealth of Puerto Rico, the Commonwealth of the Northern Mariana 
Islands, Guam, American Samoa, the U.S. Virgin Islands, and the Pacific 
Island Governments.
    Vegetable oil means a non-petroleum oil or fat of vegetable origin, 
including but not limited to oils and fats derived from plant seeds, 
nuts, fruits, and kernels.
    Vessel means every description of watercraft or other artificial 
contrivance used, or capable of being used, as a means of 
transportation on water, other than a public vessel.
    Wetlands means those areas that are inundated or saturated by 
surface or groundwater at a frequency or duration sufficient to 
support, and that under normal circumstances do support, a prevalence 
of vegetation typically adapted for life in saturated soil conditions. 
Wetlands generally include playa lakes, swamps, marshes, bogs, and 
similar areas such as sloughs, prairie potholes, wet meadows, prairie 
river overflows, mudflats, and natural ponds.
    Worst case discharge for an onshore non-transportation-related 
facility means the largest foreseeable discharge in adverse weather 
conditions as determined using the worksheets in Appendix D to this 
part.


Sec. 112.3  Requirement to prepare and implement a Spill Prevention, 
Control, and Countermeasure Plan.

    The owner or operator of an onshore or offshore facility subject to 
this section must prepare a Spill Prevention, Control, and 
Countermeasure Plan (hereafter ``SPCC Plan'' or ``Plan),'' in writing, 
and in accordance with Sec. 112.7, and any other applicable section of 
this part.
    (a) If your onshore or offshore facility was in operation on or 
before August 16, 2002, you must maintain your Plan, but must amend it, 
if necessary to ensure compliance with this part, on or before February 
17, 2003, and must implement the amended Plan as soon as possible, but 
not later than August 18, 2003. If your onshore or offshore facility 
becomes operational after August 16, 2002, through August 18, 2003, and 
could reasonably be expected to have a discharge as described in 
Sec. 112.1(b), you must prepare a Plan on or before August 18, 2003, 
and fully implement it as soon as possible, but not later than August 
18, 2003.
    (b) If you are the owner or operator of an onshore or offshore 
facility that becomes operational after August 18, 2003, and could 
reasonably be expected to have a discharge as described in 
Sec. 112.1(b), you must prepare and implement a Plan before you begin 
operations.
    (c) If you are the owner or operator of an onshore or offshore 
mobile facility, such as an onshore drilling or workover rig, barge 
mounted offshore drilling or workover rig, or portable fueling 
facility, you must prepare, implement, and maintain a facility Plan as 
required by this section. This provision does not require that you 
prepare a new Plan each time you move the facility to a new site. The 
Plan may be a general plan. When you move the mobile or portable 
facility, you must locate and install it using the discharge prevention 
practices outlined in the Plan for the facility. You may not operate a 
mobile or portable facility subject to this part unless you have 
implemented the Plan. The Plan is applicable only while the facility is 
in a fixed (non-transportation) operating mode.
    (d) A licensed Professional Engineer must review and certify a Plan 
for it to be effective to satisfy the requirements of this part.
    (1) By means of this certification the Professional Engineer 
attests:
    (i) That he is familiar with the requirements of this part ;
    (ii) That he or his agent has visited and examined the facility;
    (iii) That the Plan has been prepared in accordance with good 
engineering practice, including consideration of applicable industry 
standards, and with the requirements of this part;
    (iv) That procedures for required inspections and testing have been 
established; and
    (v) That the Plan is adequate for the facility.
    (2) Such certification shall in no way relieve the owner or 
operator of a facility of his duty to prepare and fully implement such 
Plan in accordance with the requirements of this part.
    (e) If you are the owner or operator of a facility for which a Plan 
is required under this section, you must:
    (1) Maintain a complete copy of the Plan at the facility if the 
facility is normally attended at least four hours per day, or at the 
nearest field office if the facility is not so attended, and
    (2) Have the Plan available to the Regional Administrator for on-
site review during normal working hours.
    (f) Extension of time. (1) The Regional Administrator may authorize 
an extension of time for the preparation and full implementation of a 
Plan, or any amendment thereto, beyond the time permitted for the 
preparation, implementation, or amendment of a

[[Page 47144]]

Plan under this part, when he finds that the owner or operator of a 
facility subject to this section, cannot fully comply with the 
requirements as a result of either nonavailability of qualified 
personnel, or delays in construction or equipment delivery beyond the 
control and without the fault of such owner or operator or his agents 
or employees.
    (2) If you are an owner or operator seeking an extension of time 
under paragraph (f)(1) of this section, you may submit a written 
extension request to the Regional Administrator. Your request must 
include:
    (i) A full explanation of the cause for any such delay and the 
specific aspects of the Plan affected by the delay;
    (ii) A full discussion of actions being taken or contemplated to 
minimize or mitigate such delay; and
    (iii) A proposed time schedule for the implementation of any 
corrective actions being taken or contemplated, including interim dates 
for completion of tests or studies, installation and operation of any 
necessary equipment, or other preventive measures. In addition you may 
present additional oral or written statements in support of your 
extension request.
    (3) The submission of a written extension request under paragraph 
(f)(2) of this section does not relieve you of your obligation to 
comply with the requirements of this part. The Regional Administrator 
may request a copy of your Plan to evaluate the extension request. When 
the Regional Administrator authorizes an extension of time for 
particular equipment or other specific aspects of the Plan, such 
extension does not affect your obligation to comply with the 
requirements related to other equipment or other specific aspects of 
the Plan for which the Regional Administrator has not expressly 
authorized an extension.


Sec. 112.4  Amendment of Spill Prevention, Control, and Countermeasure 
Plan by Regional Administrator.

    If you are the owner or operator of a facility subject to this 
part, you must:
    (a) Notwithstanding compliance with Sec. 112.3, whenever your 
facility has discharged more than 1,000 U.S. gallons of oil in a single 
discharge as described in Sec. 112.1(b), or discharged 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, submit the 
following information to the Regional Administrator within 60 days from 
the time the facility becomes subject to this section:
    (1) Name of the facility;
    (2) Your name;
    (3) Location of the facility;
    (4) Maximum storage or handling capacity of the facility and normal 
daily throughput;
    (5) Corrective action and countermeasures you have taken, including 
a description of equipment repairs and replacements;
    (6) An adequate description of the facility, including maps, flow 
diagrams, and topographical maps, as necessary;
    (7) The cause of such discharge as described in Sec. 112.1(b), 
including a failure analysis of the system or subsystem in which the 
failure occurred;
    (8) Additional preventive measures you have taken or contemplated 
to minimize the possibility of recurrence; and
    (9) Such other information as the Regional Administrator may 
reasonably require pertinent to the Plan or discharge.
    (b) Take no action under this section until it applies to your 
facility. This section does not apply until the expiration of the time 
permitted for the initial preparation and implementation of the Plan 
under Sec. 112.3, but not including any amendments to the Plan.
    (c) Send to the appropriate agency or agencies in charge of oil 
pollution control activities in the State in which the facility is 
located a complete copy of all information you provided to the Regional 
Administrator under paragraph (a) of this section. Upon receipt of the 
information such State agency or agencies may conduct a review and make 
recommendations to the Regional Administrator as to further procedures, 
methods, equipment, and other requirements necessary to prevent and to 
contain discharges from your facility.
    (d) Amend your Plan, if after review by the Regional Administrator 
of the information you submit under paragraph (a) of this section, or 
submission of information to EPA by the State agency under paragraph 
(c) of this section, or after on-site review of your Plan, the Regional 
Administrator requires that you do so. The Regional Administrator may 
require you to amend your Plan if he finds that it does not meet the 
requirements of this part or that amendment is necessary to prevent and 
contain discharges from your facility.
    (e) Act in accordance with this paragraph when the Regional 
Administrator proposes by certified mail or by personal delivery that 
you amend your SPCC Plan. If the owner or operator is a corporation, he 
must also notify by mail the registered agent of such corporation, if 
any and if known, in the State in which the facility is located. The 
Regional Administrator must specify the terms of such proposed 
amendment. Within 30 days from receipt of such notice, you may submit 
written information, views, and arguments on the proposed amendment. 
After considering all relevant material presented, the Regional 
Administrator must either notify you of any amendment required or 
rescind the notice. You must amend your Plan as required within 30 days 
after such notice, unless the Regional Administrator, for good cause, 
specifies another effective date. You must implement the amended Plan 
as soon as possible, but not later than six months after you amend your 
Plan, unless the Regional Administrator specifies another date.
    (f) If you appeal a decision made by the Regional Administrator 
requiring an amendment to an SPCC Plan, send the appeal to the EPA 
Administrator in writing within 30 days of receipt of the notice from 
the Regional Administrator requiring the amendment under paragraph (e) 
of this section. You must send a complete copy of the appeal to the 
Regional Administrator at the time you make the appeal. The appeal must 
contain a clear and concise statement of the issues and points of fact 
in the case. It may also contain additional information from you, or 
from any other person. The EPA Administrator may request additional 
information from you, or from any other person. The EPA Administrator 
must render a decision within 60 days of receiving the appeal and must 
notify you of his decision.


Sec. 112.5  Amendment of Spill Prevention, Control, and Countermeasure 
Plan by owners or operators.

    If you are the owner or operator of a facility subject to this 
part, you must:
    (a) Amend the SPCC Plan for your facility in accordance with the 
general requirements in Sec. 112.7, and with any specific section of 
this part applicable to your facility, when there is a change in the 
facility design, construction, operation, or maintenance that 
materially affects its potential for a discharge as described in 
Sec. 112.1(b). Examples of changes that may require amendment of the 
Plan include, but are not limited to: commissioning or decommissioning 
containers; replacement, reconstruction, or movement of containers; 
reconstruction, replacement, or installation of piping systems; 
construction or demolition that might alter secondary containment 
structures; changes of product or service; or revision of standard 
operation or maintenance procedures at

[[Page 47145]]

a facility. An amendment made under this section must be prepared 
within six months, and implemented as soon as possible, but not later 
than six months following preparation of the amendment.
    (b) Notwithstanding compliance with paragraph (a) of this section, 
complete a review and evaluation of the SPCC Plan at least once every 
five years from the date your facility becomes subject to this part; 
or, if your facility was in operation on or before August 16, 2002, 
five years from the date your last review was required under this part. 
As a result of this review and evaluation, you must amend your SPCC 
Plan within six months of the review to include more effective 
prevention and control technology if the technology has been field-
proven at the time of the review and will significantly reduce the 
likelihood of a discharge as described in Sec. 112.1(b) from the 
facility. You must implement any amendment as soon as possible, but not 
later than six months following preparation of any amendment. You must 
document your completion of the review and evaluation, and must sign a 
statement as to whether you will amend the Plan, either at the 
beginning or end of the Plan or in a log or an appendix to the Plan. 
The following words will suffice, ``I have completed review and 
evaluation of the SPCC Plan for (name of facility) on (date), and will 
(will not) amend the Plan as a result.''
    (c) Have a Professional Engineer certify any technical amendment to 
your Plan in accordance with Sec. 112.3(d).


Sec. 112.6  [Reserved]


Sec. 112.7  General requirements for Spill Prevention, Control, and 
Countermeasure Plans.

    If you are the owner or operator of a facility subject to this part 
you must prepare a Plan in accordance with good engineering practices. 
The Plan must have the full approval of management at a level of 
authority to commit the necessary resources to fully implement the 
Plan. You must prepare the Plan in writing. If you do not follow the 
sequence specified in this section for the Plan, you must prepare an 
equivalent Plan acceptable to the Regional Administrator that meets all 
of the applicable requirements listed in this part, and you must 
supplement it with a section cross-referencing the location of 
requirements listed in this part and the equivalent requirements in the 
other prevention plan. If the Plan calls for additional facilities or 
procedures, methods, or equipment not yet fully operational, you must 
discuss these items in separate paragraphs, and must explain separately 
the details of installation and operational start-up. As detailed 
elsewhere in this section, you must also:
    (a)(1) Include a discussion of your facility's conformance with the 
requirements listed in this part.
    (2) Comply with all applicable requirements listed in this part. 
Your Plan may deviate from the requirements in paragraphs (g), (h)(2) 
and (3), and (i) of this section and the requirements in subparts B and 
C of this part, except the secondary containment requirements in 
paragraphs (c) and (h)(1) of this section, and 
Secs. 112.8(c)(2),112.8(c)(11), 112.9(c)(2), 112.10(c), 112.12(c)(2), 
112.12(c)(11),112.13(c)(2), and 112.14(c), where applicable to a 
specific facility, if you provide equivalent environmental protection 
by some other means of spill prevention, control, or countermeasure. 
Where your Plan does not conform to the applicable requirements in 
paragraphs (g), (h)(2) and (3), and (i) of this section, or the 
requirements of subparts B and C of this part, except the secondary 
containment requirements in paragraphs (c) and (h)(1) of this section, 
and Secs. 112.8(c)(2), 112.8(c)(11), 112.9(c)(2), 112.10(c), 
112.12(c)(2), 112.12(c)(11), 112.13(c)(2), and 112.14(c), you must 
state the reasons for nonconformance in your Plan and describe in 
detail alternate methods and how you will achieve equivalent 
environmental protection. If the Regional Administrator determines that 
the measures described in your Plan do not provide equivalent 
environmental protection, he may require that you amend your Plan, 
following the procedures in Sec. 112.4(d) and (e).
    (3) Describe in your Plan the physical layout of the facility and 
include a facility diagram, which must mark the location and contents 
of each container. The facility diagram must include completely buried 
tanks that are otherwise exempted from the requirements of this part 
under Sec. 112.1(d)(4). The facility diagram must also include all 
transfer stations and connecting pipes. You must also address in your 
Plan:
    (i) The type of oil in each container and its storage capacity;
    (ii) Discharge prevention measures including procedures for routine 
handling of products (loading, unloading, and facility transfers, 
etc.);
    (iii) Discharge or drainage controls such as secondary containment 
around containers and other structures, equipment, and procedures for 
the control of a discharge;
    (iv) Countermeasures for discharge discovery, response, and cleanup 
(both the facility's capability and those that might be required of a 
contractor);
    (v) Methods of disposal of recovered materials in accordance with 
applicable legal requirements; and
    (vi) Contact list and phone numbers for the facility response 
coordinator, National Response Center, cleanup contractors with whom 
you have an agreement for response, and all appropriate Federal, State, 
and local agencies who must be contacted in case of a discharge as 
described in Sec. 112.1(b).
    (4) Unless you have submitted a response plan under Sec. 112.20, 
provide information and procedures in your Plan to enable a person 
reporting a discharge as described in Sec. 112.1(b) to relate 
information on the exact address or location and phone number of the 
facility; the date and time of the discharge, the type of material 
discharged; estimates of the total quantity discharged; estimates of 
the quantity discharged as described in Sec. 112.1(b); the source of 
the discharge; a description of all affected media; the cause of the 
discharge; any damages or injuries caused by the discharge; actions 
being used to stop, remove, and mitigate the effects of the discharge; 
whether an evacuation may be needed; and, the names of individuals and/
or organizations who have also been contacted.
    (5) Unless you have submitted a response plan under Sec. 112.20, 
organize portions of the Plan describing procedures you will use when a 
discharge occurs in a way that will make them readily usable in an 
emergency, and include appropriate supporting material as appendices.
    (b) Where experience indicates a reasonable potential for equipment 
failure (such as loading or unloading equipment, tank overflow, 
rupture, or leakage, or any other equipment known to be a source of a 
discharge), include in your Plan a prediction of the direction, rate of 
flow, and total quantity of oil which could be discharged from the 
facility as a result of each type of major equipment failure.
    (c) Provide appropriate containment and/or diversionary structures 
or equipment to prevent a discharge as described in Sec. 112.1(b). The 
entire containment system, including walls and floor, must be capable 
of containing oil and must be constructed so that any discharge from a 
primary containment system, such as a tank or pipe, will not escape the 
containment system before cleanup occurs. At a minimum, you must use 
one of the following prevention systems or its equivalent:

[[Page 47146]]

    (1) For onshore facilities:
    (i) Dikes, berms, or retaining walls sufficiently impervious to 
contain oil;
    (ii) Curbing;
    (iii) Culverting, gutters, or other drainage systems;
    (iv) Weirs, booms, or other barriers;
    (v) Spill diversion ponds;
    (vi) Retention ponds; or
    (vii) Sorbent materials.
    (2) For offshore facilities:
    (i) Curbing or drip pans; or
    (ii) Sumps and collection systems.
    (d) If you determine that the installation of any of the structures 
or pieces of equipment listed in paragraphs (c) and (h)(1) of this 
section, and Secs. 112.8(c)(2), 112.8(c)(11), 112.9(c)(2), 112.10(c), 
112.12(c)(2), 112.12(c)(11), 112.13(c)(2), and 112.14(c) to prevent a 
discharge as described in Sec. 112.1(b) from any onshore or offshore 
facility is not practicable, you must clearly explain in your Plan why 
such measures are not practicable; for bulk storage containers, conduct 
both periodic integrity testing of the containers and periodic 
integrity and leak testing of the valves and piping; and, unless you 
have submitted a response plan under Sec. 112.20, provide in your Plan 
the following:
    (1) An oil spill contingency plan following the provisions of part 
109 of this chapter.
    (2) A written commitment of manpower, equipment, and materials 
required to expeditiously control and remove any quantity of oil 
discharged that may be harmful.
    (e) Inspections, tests, and records. Conduct inspections and tests 
required by this part in accordance with written procedures that you or 
the certifying engineer develop for the facility. You must keep these 
written procedures and a record of the inspections and tests, signed by 
the appropriate supervisor or inspector, with the SPCC Plan for a 
period of three years. Records of inspections and tests kept under 
usual and customary business practices will suffice for purposes of 
this paragraph.
    (f) Personnel, training, and discharge prevention procedures. (1) 
At a minimum, train your oil-handling personnel in the operation and 
maintenance of equipment to prevent discharges; discharge procedure 
protocols; applicable pollution control laws, rules, and regulations; 
general facility operations; and, the contents of the facility SPCC 
Plan.
    (2) Designate a person at each applicable facility who is 
accountable for discharge prevention and who reports to facility 
management.
    (3) Schedule and conduct discharge prevention briefings for your 
oil-handling personnel at least once a year to assure adequate 
understanding of the SPCC Plan for that facility. Such briefings must 
highlight and describe known discharges as described in Sec. 112.1(b) 
or failures, malfunctioning components, and any recently developed 
precautionary measures.
    (g) Security (excluding oil production facilities). (1) Fully fence 
each facility handling, processing, or storing oil, and lock and/or 
guard entrance gates when the facility is not in production or is 
unattended.
    (2) Ensure that the master flow and drain valves and any other 
valves permitting direct outward flow of the container's contents to 
the surface have adequate security measures so that they remain in the 
closed position when in non-operating or non-standby status.
    (3) Lock the starter control on each oil pump in the ``off'' 
position and locate it at a site accessible only to authorized 
personnel when the pump is in a non-operating or non-standby status.
    (4) Securely cap or blank-flange the loading/unloading connections 
of oil pipelines or facility piping when not in service or when in 
standby service for an extended time. This security practice also 
applies to piping that is emptied of liquid content either by draining 
or by inert gas pressure.
    (5) Provide facility lighting commensurate with the type and 
location of the facility that will assist in the:
    (i) Discovery of discharges occurring during hours of darkness, 
both by operating personnel, if present, and by non-operating personnel 
(the general public, local police, etc.); and
    (ii) Prevention of discharges occurring through acts of vandalism.
    (h) Facility tank car and tank truck loading/unloading rack 
(excluding offshore facilities). (1) Where loading/unloading area 
drainage does not flow into a catchment basin or treatment facility 
designed to handle discharges, use a quick drainage system for tank car 
or tank truck loading and unloading areas. You must design any 
containment system to hold at least the maximum capacity of any single 
compartment of a tank car or tank truck loaded or unloaded at the 
facility.
    (2) Provide an interlocked warning light or physical barrier 
system, warning signs, wheel chocks, or vehicle break interlock system 
in loading/unloading areas to prevent vehicles from departing before 
complete disconnection of flexible or fixed oil transfer lines.
    (3) Prior to filling and departure of any tank car or tank truck, 
closely inspect for discharges the lowermost drain and all outlets of 
such vehicles, and if necessary, ensure that they are tightened, 
adjusted, or replaced to prevent liquid discharge while in transit.
    (i) If a field-constructed aboveground container undergoes a 
repair, alteration, reconstruction, or a change in service that might 
affect the risk of a discharge or failure due to brittle fracture or 
other catastrophe, or has discharged oil or failed due to brittle 
fracture failure or other catastrophe, evaluate the container for risk 
of discharge or failure due to brittle fracture or other catastrophe, 
and as necessary, take appropriate action.
    (j) In addition to the minimal prevention standards listed under 
this section, include in your Plan a complete discussion of conformance 
with the applicable requirements and other effective discharge 
prevention and containment procedures listed in this part or any 
applicable more stringent State rules, regulations, and guidelines.


    3. Part 112 is amended adding subpart B consisting of Secs. 112.8 
through 112.11 to read as follows:
Subpart B--Requirements for Petroleum Oils and Non-Petroleum Oils, 
Except Animal Fats and Oils and Greases, and Fish and Marine Mammal 
Oils; and Vegetable Oils (Including Oils from Seeds, Nuts, Fruits, and 
Kernels)
Sec.
112.8  Spill Prevention, Control, and Countermeasure Plan 
requirements for onshore facilities (excluding production 
facilities).
112.9  Spill Prevention, Control, and Countermeasure Plan 
requirements for onshore oil production facilities.
112.10  Spill Prevention, Control, and Countermeasure Plan 
requirements for onshore oil drilling and workover facilities.
112.11  Spill Prevention, Control, and Countermeasure Plan 
requirements for offshore oil drilling, production, or workover 
facilities.

Subpart B--Requirements for Petroleum Oils and Non-Petroleum Oils, 
Except Animal Fats and Oils and Greases, and Fish and Marine Mammal 
Oils; and Vegetable Oils (Including Oils from Seeds, Nuts, Fruits, 
and Kernels)


Sec. 112.8  Spill Prevention, Control, and Countermeasure Plan 
requirements for onshore facilities (excluding production facilities).

    If you are the owner or operator of an onshore facility (excluding 
a production facility), you must:
    (a) Meet the general requirements for the Plan listed under 
Sec. 112.7, and the specific discharge prevention and containment 
procedures listed in this section.

[[Page 47147]]

    (b) Facility drainage. (1) Restrain drainage from diked storage 
areas by valves to prevent a discharge into the drainage system or 
facility effluent treatment system, except where facility systems are 
designed to control such discharge. You may empty diked areas by pumps 
or ejectors; however, you must manually activate these pumps or 
ejectors and must inspect the condition of the accumulation before 
starting, to ensure no oil will be discharged.
    (2) Use valves of manual, open-and-closed design, for the drainage 
of diked areas. You may not use flapper-type drain valves to drain 
diked areas. If your facility drainage drains directly into a 
watercourse and not into an on-site wastewater treatment plant, you 
must inspect and may drain uncontaminated retained stormwater, as 
provided in paragraphs (c)(3)(ii), (iii), and (iv) of this section.
    (3) Design facility drainage systems from undiked areas with a 
potential for a discharge (such as where piping is located outside 
containment walls or where tank truck discharges may occur outside the 
loading area) to flow into ponds, lagoons, or catchment basins designed 
to retain oil or return it to the facility. You must not locate 
catchment basins in areas subject to periodic flooding.
    (4) If facility drainage is not engineered as in paragraph (b)(3) 
of this section, equip the final discharge of all ditches inside the 
facility with a diversion system that would, in the event of an 
uncontrolled discharge, retain oil in the facility.
    (5) Where drainage waters are treated in more than one treatment 
unit and such treatment is continuous, and pump transfer is needed, 
provide two ``lift'' pumps and permanently install at least one of the 
pumps. Whatever techniques you use, you must engineer facility drainage 
systems to prevent a discharge as described in Sec. 112.1(b) in case 
there is an equipment failure or human error at the facility.
    (c) Bulk storage containers. (1) Not use a container for the 
storage of oil unless its material and construction are compatible with 
the material stored and conditions of storage such as pressure and 
temperature.
    (2) Construct all bulk storage container installations so that you 
provide a secondary means of containment for the entire capacity of the 
largest single container and sufficient freeboard to contain 
precipitation. You must ensure that diked areas are sufficiently 
impervious to contain discharged oil. Dikes, containment curbs, and 
pits are commonly employed for this purpose. You may also use an 
alternative system consisting of a drainage trench enclosure that must 
be arranged so that any discharge will terminate and be safely confined 
in a facility catchment basin or holding pond.
    (3) Not allow drainage of uncontaminated rainwater from the diked 
area into a storm drain or discharge of an effluent into an open 
watercourse, lake, or pond, bypassing the facility treatment system 
unless you:
    (i) Normally keep the bypass valve sealed closed.
    (ii) Inspect the retained rainwater to ensure that its presence 
will not cause a discharge as described in Sec. 112.1(b).
    (iii) Open the bypass valve and reseal it following drainage under 
responsible supervision; and
    (iv) Keep adequate records of such events, for example, any records 
required under permits issued in accordance with Secs. 122.41(j)(2) and 
122.41(m)(3) of this chapter.
    (4) Protect any completely buried metallic storage tank installed 
on or after January 10, 1974 from corrosion by coatings or cathodic 
protection compatible with local soil conditions. You must regularly 
leak test such completely buried metallic storage tanks.
    (5) Not use partially buried or bunkered metallic tanks for the 
storage of oil, unless you protect the buried section of the tank from 
corrosion. You must protect partially buried and bunkered tanks from 
corrosion by coatings or cathodic protection compatible with local soil 
conditions.
    (6) Test each aboveground container for integrity on a regular 
schedule, and whenever you make material repairs. The frequency of and 
type of testing must take into account container size and design (such 
as floating roof, skid-mounted, elevated, or partially buried). You 
must combine visual inspection with another testing technique such as 
hydrostatic testing, radiographic testing, ultrasonic testing, acoustic 
emissions testing, or another system of non-destructive shell testing. 
You must keep comparison records and you must also inspect the 
container's supports and foundations. In addition, you must frequently 
inspect the outside of the container for signs of deterioration, 
discharges, or accumulation of oil inside diked areas. Records of 
inspections and tests kept under usual and customary business practices 
will suffice for purposes of this paragraph.
    (7) Control leakage through defective internal heating coils by 
monitoring the steam return and exhaust lines for contamination from 
internal heating coils that discharge into an open watercourse, or pass 
the steam return or exhaust lines through a settling tank, skimmer, or 
other separation or retention system.
    (8) Engineer or update each container installation in accordance 
with good engineering practice to avoid discharges. You must provide at 
least one of the following devices:
    (i) High liquid level alarms with an audible or visual signal at a 
constantly attended operation or surveillance station. In smaller 
facilities an audible air vent may suffice.
    (ii) High liquid level pump cutoff devices set to stop flow at a 
predetermined container content level.
    (iii) Direct audible or code signal communication between the 
container gauger and the pumping station.
    (iv) A fast response system for determining the liquid level of 
each bulk storage container such as digital computers, telepulse, or 
direct vision gauges. If you use this alternative, a person must be 
present to monitor gauges and the overall filling of bulk storage 
containers.
    (v) You must regularly test liquid level sensing devices to ensure 
proper operation.
    (9) Observe effluent treatment facilities frequently enough to 
detect possible system upsets that could cause a discharge as described 
in Sec. 112.1(b).
    (10) Promptly correct visible discharges which result in a loss of 
oil from the container, including but not limited to seams, gaskets, 
piping, pumps, valves, rivets, and bolts. You must promptly remove any 
accumulations of oil in diked areas.
    (11) Position or locate mobile or portable oil storage containers 
to prevent a discharge as described in Sec. 112.1(b). You must furnish 
a secondary means of containment, such as a dike or catchment basin, 
sufficient to contain the capacity of the largest single compartment or 
container with sufficient freeboard to contain precipitation.
    (d) Facility transfer operations, pumping, and facility process. 
(1) Provide buried piping that is installed or replaced on or after 
August 16, 2002, with a protective wrapping and coating. You must also 
cathodically protect such buried piping installations or otherwise 
satisfy the corrosion protection standards for piping in part 280 of 
this chapter or a State program approved under part 281 of this 
chapter. If a section of buried line is exposed for any reason, you 
must carefully inspect it for deterioration. If you find corrosion 
damage, you must undertake additional examination and corrective action 
as

[[Page 47148]]

indicated by the magnitude of the damage.
    (2) Cap or blank-flange the terminal connection at the transfer 
point and mark it as to origin when piping is not in service or is in 
standby service for an extended time.
    (3) Properly design pipe supports to minimize abrasion and 
corrosion and allow for expansion and contraction.
    (4) Regularly inspect all aboveground valves, piping, and 
appurtenances. During the inspection you must assess the general 
condition of items, such as flange joints, expansion joints, valve 
glands and bodies, catch pans, pipeline supports, locking of valves, 
and metal surfaces. You must also conduct integrity and leak testing of 
buried piping at the time of installation, modification, construction, 
relocation, or replacement.
    (5) Warn all vehicles entering the facility to be sure that no 
vehicle will endanger aboveground piping or other oil transfer 
operations.


Sec. 112.9  Spill Prevention, Control, and Countermeasure Plan 
requirements for onshore oil production facilities.

    If you are the owner or operator of an onshore production facility, 
you must:
    (a) Meet the general requirements for the Plan listed under 
Sec. 112.7, and the specific discharge prevention and containment 
procedures listed under this section.
    (b) Oil production facility drainage. (1) At tank batteries and 
separation and treating areas where there is a reasonable possibility 
of a discharge as described in Sec. 112.1(b), close and seal at all 
times drains of dikes or drains of equivalent measures required under 
Sec. 112.7(c)(1), except when draining uncontaminated rainwater. Prior 
to drainage, you must inspect the diked area and take action as 
provided in Sec. 112.8(c)(3)(ii), (iii), and (iv). You must remove 
accumulated oil on the rainwater and return it to storage or dispose of 
it in accordance with legally approved methods.
    (2) Inspect at regularly scheduled intervals field drainage systems 
(such as drainage ditches or road ditches), and oil traps, sumps, or 
skimmers, for an accumulation of oil that may have resulted from any 
small discharge. You must promptly remove any accumulations of oil.
    (c) Oil production facility bulk storage containers. (1) Not use a 
container for the storage of oil unless its material and construction 
are compatible with the material stored and the conditions of storage.
    (2) Provide all tank battery, separation, and treating facility 
installations with a secondary means of containment for the entire 
capacity of the largest single container and sufficient freeboard to 
contain precipitation. You must safely confine drainage from undiked 
areas in a catchment basin or holding pond.
    (3) Periodically and upon a regular schedule visually inspect each 
container of oil for deterioration and maintenance needs, including the 
foundation and support of each container that is on or above the 
surface of the ground.
    (4) Engineer or update new and old tank battery installations in 
accordance with good engineering practice to prevent discharges. You 
must provide at least one of the following:
    (i) Container capacity adequate to assure that a container will not 
overfill if a pumper/gauger is delayed in making regularly scheduled 
rounds.
    (ii) Overflow equalizing lines between containers so that a full 
container can overflow to an adjacent container.
    (iii) Vacuum protection adequate to prevent container collapse 
during a pipeline run or other transfer of oil from the container.
    (iv) High level sensors to generate and transmit an alarm signal to 
the computer where the facility is subject to a computer production 
control system.
    (d) Facility transfer operations, oil production facility. (1) 
Periodically and upon a regular schedule inspect all aboveground valves 
and piping associated with transfer operations for the general 
condition of flange joints, valve glands and bodies, drip pans, pipe 
supports, pumping well polish rod stuffing boxes, bleeder and gauge 
valves, and other such items.
    (2) Inspect saltwater (oil field brine) disposal facilities often, 
particularly following a sudden change in atmospheric temperature, to 
detect possible system upsets capable of causing a discharge.
    (3) Have a program of flowline maintenance to prevent discharges 
from each flowline.


Sec. 112.10  Spill Prevention, Control, and Countermeasure Plan 
requirements for onshore oil drilling and workover facilities.

    If you are the owner or operator of an onshore oil drilling and 
workover facility, you must:
    (a) Meet the general requirements listed under Sec. 112.7, and also 
meet the specific discharge prevention and containment procedures 
listed under this section.
    (b) Position or locate mobile drilling or workover equipment so as 
to prevent a discharge as described in Sec. 112.1(b).
    (c) Provide catchment basins or diversion structures to intercept 
and contain discharges of fuel, crude oil, or oily drilling fluids.
    (d) Install a blowout prevention (BOP) assembly and well control 
system before drilling below any casing string or during workover 
operations. The BOP assembly and well control system must be capable of 
controlling any well-head pressure that may be encountered while that 
BOP assembly and well control system are on the well.


Sec. 112.11  Spill Prevention, Control, and Countermeasure Plan 
requirements for offshore oil drilling, production, or workover 
facilities.

    If you are the owner or operator of an offshore oil drilling, 
production, or workover facility, you must:
    (a) Meet the general requirements listed under Sec. 112.7, and also 
meet the specific discharge prevention and containment procedures 
listed under this section.
    (b) Use oil drainage collection equipment to prevent and control 
small oil discharges around pumps, glands, valves, flanges, expansion 
joints, hoses, drain lines, separators, treaters, tanks, and associated 
equipment. You must control and direct facility drains toward a central 
collection sump to prevent the facility from having a discharge as 
described in Sec. 112.1(b). Where drains and sumps are not practicable, 
you must remove oil contained in collection equipment as often as 
necessary to prevent overflow.
    (c) For facilities employing a sump system, provide adequately 
sized sump and drains and make available a spare pump to remove liquid 
from the sump and assure that oil does not escape. You must employ a 
regularly scheduled preventive maintenance inspection and testing 
program to assure reliable operation of the liquid removal system and 
pump start-up device. Redundant automatic sump pumps and control 
devices may be required on some installations.
    (d) At facilities with areas where separators and treaters are 
equipped with dump valves which predominantly fail in the closed 
position and where pollution risk is high, specially equip the facility 
to prevent the discharge of oil. You must prevent the discharge of oil 
by:
    (1) Extending the flare line to a diked area if the separator is 
near shore;
    (2) Equipping the separator with a high liquid level sensor that 
will automatically shut in wells producing to the separator; or
    (3) Installing parallel redundant dump valves.
    (e) Equip atmospheric storage or surge containers with high liquid 
level

[[Page 47149]]

sensing devices that activate an alarm or control the flow, or 
otherwise prevent discharges.
    (f) Equip pressure containers with high and low pressure sensing 
devices that activate an alarm or control the flow.
    (g) Equip containers with suitable corrosion protection.
    (h) Prepare and maintain at the facility a written procedure within 
the Plan for inspecting and testing pollution prevention equipment and 
systems.
    (i) Conduct testing and inspection of the pollution prevention 
equipment and systems at the facility on a scheduled periodic basis, 
commensurate with the complexity, conditions, and circumstances of the 
facility and any other appropriate regulations. You must use simulated 
discharges for testing and inspecting human and equipment pollution 
control and countermeasure systems.
    (j) Describe in detailed records surface and subsurface well shut-
in valves and devices in use at the facility for each well sufficiently 
to determine their method of activation or control, such as pressure 
differential, change in fluid or flow conditions, combination of 
pressure and flow, manual or remote control mechanisms.
    (k) Install a BOP assembly and well control system during workover 
operations and before drilling below any casing string. The BOP 
assembly and well control system must be capable of controlling any 
well-head pressure that may be encountered while the BOP assembly and 
well control system are on the well.
    (l) Equip all manifolds (headers) with check valves on individual 
flowlines.
    (m) Equip the flowline with a high pressure sensing device and 
shut-in valve at the wellhead if the shut-in well pressure is greater 
than the working pressure of the flowline and manifold valves up to and 
including the header valves. Alternatively you may provide a pressure 
relief system for flowlines.
    (n) Protect all piping appurtenant to the facility from corrosion, 
such as with protective coatings or cathodic protection.
    (o) Adequately protect sub-marine piping appurtenant to the 
facility against environmental stresses and other activities such as 
fishing operations.
    (p) Maintain sub-marine piping appurtenant to the facility in good 
operating condition at all times. You must periodically and according 
to a schedule inspect or test such piping for failures. You must 
document and keep a record of such inspections or tests at the 
facility.


    4. Part 112 is amended by adding subpart C consisting of 
Secs. 112.12 through 112.15 to read as follows:
Subpart C--Requirements for Animal Fats and Oils and Greases, and Fish 
and Marine Mammal Oils; and for Vegetable Oils, Including Oils from 
Seeds, Nuts, Fruits and Kernels
Sec.
112.12   Spill Prevention, Control, and Countermeasure Plan 
requirements for onshore facilities (excluding production 
facilities).
112.13   Spill Prevention, Control, and Countermeasure Plan 
requirements for onshore oil production facilities.
112.14   Spill Prevention, Control, and Countermeasure Plan 
requirements for onshore oil drilling and workover facilities.
112.15   Spill Prevention, Control, and Countermeasure Plan 
requirements for offshore oil drilling, production, or workover 
facilities.

Subpart C--Requirements for Animal Fats and Oils and Greases, and 
Fish and Marine Mammal Oils; and for Vegetable Oils, including Oils 
from Seeds, Nuts, Fruits, and Kernels.


Sec. 112.12  Spill Prevention, Control, and Countermeasure Plan 
requirements for onshore facilities (excluding production facilities)

    If you are the owner or operator of an onshore facility (excluding 
a production facility), you must:
    (a) Meet the general requirements for the Plan listed under 
Sec. 112.7, and the specific discharge prevention and containment 
procedures listed in this section.
    (b) Facility drainage. (1) Restrain drainage from diked storage 
areas by valves to prevent a discharge into the drainage system or 
facility effluent treatment system, except where facility systems are 
designed to control such discharge. You may empty diked areas by pumps 
or ejectors; however, you must manually activate these pumps or 
ejectors and must inspect the condition of the accumulation before 
starting, to ensure no oil will be discharged.
    (2) Use valves of manual, open-and-closed design, for the drainage 
of diked areas. You may not use flapper-type drain valves to drain 
diked areas. If your facility drainage drains directly into a 
watercourse and not into an on-site wastewater treatment plant, you 
must inspect and may drain uncontaminated retained stormwater, subject 
to the requirements of paragraphs (c)(3)(ii), (iii), and (iv) of this 
section.
    (3) Design facility drainage systems from undiked areas with a 
potential for a discharge (such as where piping is located outside 
containment walls or where tank truck discharges may occur outside the 
loading area) to flow into ponds, lagoons, or catchment basins designed 
to retain oil or return it to the facility. You must not locate 
catchment basins in areas subject to periodic flooding.
    (4) If facility drainage is not engineered as in paragraph (b)(3) 
of this section, equip the final discharge of all ditches inside the 
facility with a diversion system that would, in the event of an 
uncontrolled discharge, retain oil in the facility.
    (5) Where drainage waters are treated in more than one treatment 
unit and such treatment is continuous, and pump transfer is needed, 
provide two ``lift'' pumps and permanently install at least one of the 
pumps. Whatever techniques you use, you must engineer facility drainage 
systems to prevent a discharge as described in Sec. 112.1(b) in case 
there is an equipment failure or human error at the facility.
    (c) Bulk storage containers. (1) Not use a container for the 
storage of oil unless its material and construction are compatible with 
the material stored and conditions of storage such as pressure and 
temperature.
    (2) Construct all bulk storage container installations so that you 
provide a secondary means of containment for the entire capacity of the 
largest single container and sufficient freeboard to contain 
precipitation. You must ensure that diked areas are sufficiently 
impervious to contain discharged oil. Dikes, containment curbs, and 
pits are commonly employed for this purpose. You may also use an 
alternative system consisting of a drainage trench enclosure that must 
be arranged so that any discharge will terminate and be safely confined 
in a facility catchment basin or holding pond.
    (3) Not allow drainage of uncontaminated rainwater from the diked 
area into a storm drain or discharge of an effluent into an open 
watercourse, lake, or pond, bypassing the facility treatment system 
unless you:
    (i) Normally keep the bypass valve sealed closed.
    (ii) Inspect the retained rainwater to ensure that its presence 
will not cause a discharge as described in Sec. 112.1(b).
    (iii) Open the bypass valve and reseal it following drainage under 
responsible supervision; and
    (iv) Keep adequate records of such events, for example, any records 
required under permits issued in accordance with Secs. 122.41(j)(2) and 
122.41(m)(3) of this chapter.
    (4) Protect any completely buried metallic storage tank installed 
on or after January 10, 1974 from corrosion by

[[Page 47150]]

coatings or cathodic protection compatible with local soil conditions. 
You must regularly leak test such completely buried metallic storage 
tanks.
    (5) Not use partially buried or bunkered metallic tanks for the 
storage of oil, unless you protect the buried section of the tank from 
corrosion. You must protect partially buried and bunkered tanks from 
corrosion by coatings or cathodic protection compatible with local soil 
conditions.
    (6) Test each aboveground container for integrity on a regular 
schedule, and whenever you make material repairs. The frequency of and 
type of testing must take into account container size and design (such 
as floating roof, skid-mounted, elevated, or partially buried). You 
must combine visual inspection with another testing technique such as 
hydrostatic testing, radiographic testing, ultrasonic testing, acoustic 
emissions testing, or another system of non-destructive shell testing. 
You must keep comparison records and you must also inspect the 
container's supports and foundations. In addition, you must frequently 
inspect the outside of the container for signs of deterioration, 
discharges, or accumulation of oil inside diked areas. Records of 
inspections and tests kept under usual and customary business practices 
will suffice for purposes of this paragraph.
    (7) Control leakage through defective internal heating coils by 
monitoring the steam return and exhaust lines for contamination from 
internal heating coils that discharge into an open watercourse, or pass 
the steam return or exhaust lines through a settling tank, skimmer, or 
other separation or retention system.
    (8) Engineer or update each container installation in accordance 
with good engineering practice to avoid discharges. You must provide at 
least one of the following devices:
    (i) High liquid level alarms with an audible or visual signal at a 
constantly attended operation or surveillance station. In smaller 
facilities an audible air vent may suffice.
    (ii) High liquid level pump cutoff devices set to stop flow at a 
predetermined container content level.
    (iii) Direct audible or code signal communication between the 
container gauger and the pumping station.
    (iv) A fast response system for determining the liquid level of 
each bulk storage container such as digital computers, telepulse, or 
direct vision gauges. If you use this alternative, a person must be 
present to monitor gauges and the overall filling of bulk storage 
containers.
    (v) You must regularly test liquid level sensing devices to ensure 
proper operation.
    (9) Observe effluent treatment facilities frequently enough to 
detect possible system upsets that could cause a discharge as described 
in Sec. 112.1(b).
    (10) Promptly correct visible discharges which result in a loss of 
oil from the container, including but not limited to seams, gaskets, 
piping, pumps, valves, rivets, and bolts. You must promptly remove any 
accumulations of oil in diked areas.
    (11) Position or locate mobile or portable oil storage containers 
to prevent a discharge as described in Sec. 112.1(b). You must furnish 
a secondary means of containment, such as a dike or catchment basin, 
sufficient to contain the capacity of the largest single compartment or 
container with sufficient freeboard to contain precipitation.
    (d) Facility transfer operations, pumping, and facility process. 
(1) Provide buried piping that is installed or replaced on or after 
August 16, 2002, with a protective wrapping and coating. You must also 
cathodically protect such buried piping installations or otherwise 
satisfy the corrosion protection standards for piping in part 280 of 
this chapter or a State program approved under part 281 of this 
chapter. If a section of buried line is exposed for any reason, you 
must carefully inspect it for deterioration. If you find corrosion 
damage, you must undertake additional examination and corrective action 
as indicated by the magnitude of the damage.
    (2) Cap or blank-flange the terminal connection at the transfer 
point and mark it as to origin when piping is not in service or is in 
standby service for an extended time.
    (3) Properly design pipe supports to minimize abrasion and 
corrosion and allow for expansion and contraction.
    (4) Regularly inspect all aboveground valves, piping, and 
appurtenances. During the inspection you must assess the general 
condition of items, such as flange joints, expansion joints, valve 
glands and bodies, catch pans, pipeline supports, locking of valves, 
and metal surfaces. You must also conduct integrity and leak testing of 
buried piping at the time of installation, modification, construction, 
relocation, or replacement.
    (5) Warn all vehicles entering the facility to be sure that no 
vehicle will endanger aboveground piping or other oil transfer 
operations.


Sec. 112.13  Spill Prevention, Control, and Countermeasure Plan 
requirements for onshore oil production facilities.

    If you are the owner or operator of an onshore production facility, 
you must:
    (a) Meet the general requirements for the Plan listed under 
Sec. 112.7, and the specific discharge prevention and containment 
procedures listed under this section.
    (b) Oil production facility drainage. (1) At tank batteries and 
separation and treating areas where there is a reasonable possibility 
of a discharge as described in Sec. 112.1(b), close and seal at all 
times drains of dikes or drains of equivalent measures required under 
Sec. 112.7(c)(1), except when draining uncontaminated rainwater. Prior 
to drainage, you must inspect the diked area and take action as 
provided in Sec. 112.12(c)(3)(ii), (iii), and (iv). You must remove 
accumulated oil on the rainwater and return it to storage or dispose of 
it in accordance with legally approved methods.
    (2) Inspect at regularly scheduled intervals field drainage systems 
(such as drainage ditches or road ditches), and oil traps, sumps, or 
skimmers, for an accumulation of oil that may have resulted from any 
small discharge. You must promptly remove any accumulations of oil.
    (c) Oil production facility bulk storage containers. (1) Not use a 
container for the storage of oil unless its material and construction 
are compatible with the material stored and the conditions of storage.
    (2) Provide all tank battery, separation, and treating facility 
installations with a secondary means of containment for the entire 
capacity of the largest single container and sufficient freeboard to 
contain precipitation. You must safely confine drainage from undiked 
areas in a catchment basin or holding pond.
    (3) Periodically and upon a regular schedule visually inspect each 
container of oil for deterioration and maintenance needs, including the 
foundation and support of each container that is on or above the 
surface of the ground.
    (4) Engineer or update new and old tank battery installations in 
accordance with good engineering practice to prevent discharges. You 
must provide at least one of the following:
    (i) Container capacity adequate to assure that a container will not 
overfill if a pumper/gauger is delayed in making regularly scheduled 
rounds.
    (ii) Overflow equalizing lines between containers so that a full 
container can overflow to an adjacent container.
    (iii) Vacuum protection adequate to prevent container collapse 
during a

[[Page 47151]]

pipeline run or other transfer of oil from the container.
    (iv) High level sensors to generate and transmit an alarm signal to 
the computer where the facility is subject to a computer production 
control system.
    (d) Facility transfer operations, oil production facility. (1) 
Periodically and upon a regular schedule inspect all aboveground valves 
and piping associated with transfer operations for the general 
condition of flange joints, valve glands and bodies, drip pans, pipe 
supports, pumping well polish rod stuffing boxes, bleeder and gauge 
valves, and other such items.
    (2) Inspect saltwater (oil field brine) disposal facilities often, 
particularly following a sudden change in atmospheric temperature, to 
detect possible system upsets capable of causing a discharge.
    (3) Have a program of flowline maintenance to prevent discharges 
from each flowline.


Sec. 112.14  Spill Prevention, Control, and Countermeasure Plan 
requirements for onshore oil drilling and workover facilities.

    If you are the owner or operator of an onshore oil drilling and 
workover facility, you must:
    (a) Meet the general requirements listed under Sec. 112.7, and also 
meet the specific discharge prevention and containment procedures 
listed under this section.
    (b) Position or locate mobile drilling or workover equipment so as 
to prevent a discharge as described in Sec. 112.1(b).
    (c) Provide catchment basins or diversion structures to intercept 
and contain discharges of fuel, crude oil, or oily drilling fluids.
    (d) Install a blowout prevention (BOP) assembly and well control 
system before drilling below any casing string or during workover 
operations. The BOP assembly and well control system must be capable of 
controlling any well-head pressure that may be encountered while that 
BOP assembly and well control system are on the well.


Sec. 112.15  Spill Prevention, Control, and Countermeasure Plan 
requirements for offshore oil drilling, production, or workover 
facilities.

    If you are the owner or operator of an offshore oil drilling, 
production, or workover facility, you must:
    (a) Meet the general requirements listed under Sec. 112.7, and also 
meet the specific discharge prevention and containment procedures 
listed under this section.
    (b) Use oil drainage collection equipment to prevent and control 
small oil discharges around pumps, glands, valves, flanges, expansion 
joints, hoses, drain lines, separators, treaters, tanks, and associated 
equipment. You must control and direct facility drains toward a central 
collection sump to prevent the facility from having a discharge as 
described in Sec. 112.1(b). Where drains and sumps are not practicable, 
you must remove oil contained in collection equipment as often as 
necessary to prevent overflow.
    (c) For facilities employing a sump system, provide adequately 
sized sump and drains and make available a spare pump to remove liquid 
from the sump and assure that oil does not escape. You must employ a 
regularly scheduled preventive maintenance inspection and testing 
program to assure reliable operation of the liquid removal system and 
pump start-up device. Redundant automatic sump pumps and control 
devices may be required on some installations.
    (d) At facilities with areas where separators and treaters are 
equipped with dump valves which predominantly fail in the closed 
position and where pollution risk is high, specially equip the facility 
to prevent the discharge of oil. You must prevent the discharge of oil 
by:
    (1) Extending the flare line to a diked area if the separator is 
near shore;
    (2) Equipping the separator with a high liquid level sensor that 
will automatically shut in wells producing to the separator; or
    (3) Installing parallel redundant dump valves.
    (e) Equip atmospheric storage or surge containers with high liquid 
level sensing devices that activate an alarm or control the flow, or 
otherwise prevent discharges.
    (f) Equip pressure containers with high and low pressure sensing 
devices that activate an alarm or control the flow.
    (g) Equip containers with suitable corrosion protection.
    (h) Prepare and maintain at the facility a written procedure within 
the Plan for inspecting and testing pollution prevention equipment and 
systems.
    (i) Conduct testing and inspection of the pollution prevention 
equipment and systems at the facility on a scheduled periodic basis, 
commensurate with the complexity, conditions, and circumstances of the 
facility and any other appropriate regulations. You must use simulated 
discharges for testing and inspecting human and equipment pollution 
control and countermeasure systems.
    (j) Describe in detailed records surface and subsurface well shut-
in valves and devices in use at the facility for each well sufficiently 
to determine their method of activation or control, such as pressure 
differential, change in fluid or flow conditions, combination of 
pressure and flow, manual or remote control mechanisms.
    (k) Install a BOP assembly and well control system during workover 
operations and before drilling below any casing string. The BOP 
assembly and well control system must be capable of controlling any 
well-head pressure that may be encountered while that BOP assembly and 
well control system are on the well.
    (l) Equip all manifolds (headers) with check valves on individual 
flowlines.
    (m) Equip the flowline with a high pressure sensing device and 
shut-in valve at the wellhead if the shut-in well pressure is greater 
than the working pressure of the flowline and manifold valves up to and 
including the header valves. Alternatively you may provide a pressure 
relief system for flowlines.
    (n) Protect all piping appurtenant to the facility from corrosion, 
such as with protective coatings or cathodic protection.
    (o) Adequately protect sub-marine piping appurtenant to the 
facility against environmental stresses and other activities such as 
fishing operations.
    (p) Maintain sub-marine piping appurtenant to the facility in good 
operating condition at all times. You must periodically and according 
to a schedule inspect or test such piping for failures. You must 
document and keep a record of such inspections or tests at the 
facility.


    5. Part 112 is amended by designating Secs. 112.20 and 112.21 as 
subpart D, and adding a subpart heading as follows:
Subpart D--Response Requirements
Sec.
112.20   Facility response plans.
112.21   Facility response training and drills/exercises.

Subpart D--Response Requirements

    6. Section 112.20 is amended by revising the first sentence of 
paragraph (h) to read as follows:


Sec. 112.20  Facility response plans.

* * * * *
    (h) A response plan shall follow the format of the model facility-
specific response plan included in Appendix F to this part, unless you 
have prepared an equivalent response plan acceptable to the Regional 
Administrator to meet State or other Federal requirements. * * *
* * * * *

[[Page 47152]]

Appendix C--[Amended]

    7. Appendix C of part 112 is amended by:
    a. Revising the first sentence of section 2.1; and
    b. Revising the title and first sentence of section 2.4.

Appendix C to Part 112--Substantial Harm Criteria

* * * * *

2.1  Non-Transportation-Related Facilities With a Total Oil Storage 
Capacity Greater Than or Equal to 42,000 Gallons Where Operations 
Include Over-Water Transfers of Oil

    A non-transportation-related facility with a total oil storage 
capacity greater than or equal to 42,000 gallons that transfers oil 
over water to or from vessels must submit a response plan to EPA. * 
* *
* * * * *

2.4  Proximity to Public Drinking Water Intakes at Facilities with 
a Total Oil Storage Capacity Greater than or Equal to 1 Million 
Gallons

    A facility with a total oil storage capacity greater than or 
equal to 1 million gallons must submit its response plan if it is 
located at a distance such that a discharge from the facility would 
shut down a public drinking water intake, which is analogous to a 
public water system as described at 40 CFR 143.2(c). * * *
* * * * *

Appendix D--[Amended]

    8. Appendix D of part 112 is amended by revising footnote 2 to 
section A.2 of Part A to read as follows:

Appendix D to Part 112--Determination of a Worst Case Discharge 
Planning Volume

* * * * *
    Part A * * *
* * * * *

A.2 Secondary Containment--Multiple-Tank Facilities

* * * * *
    Secondary containment is described in 40 CFR part 112, subparts 
A through C. Acceptable methods and structures for containment are 
also given in 40 CFR 112.7(c)(1).
* * * * *

Appendix F--[Amended]

    9. Appendix F of part 112 is amended by:
    a. Revising section 1.2.7;
    b. Revising the second and last sentences of section 1.4.3;
    c. Revising paragraph (7) and the undesignated paragraph and NOTE 
following paragraph (7) in section 1.7.3;
    d. Revising section 1.8.1;
    e. Revising the first two sentences of section 1.8.1.1. 
introductory text;
    f. Revising the next to the last sentence of section 1.8.1.3;
    g. Revising the next to last sentence of section 1.10.;
    h. Revising paragraph (6) of section 2.1;
    i. Remove the acronym ``SIC'' in section 3.0, and add in 
alphabetical order the acronym ``NAICS'; and.
    j. Remove the reference to ``Standard Industrial Classification 
(SIC) Code'' in Attachment F-1, General Information, and add in in 
alphabetical order a reference to ``North American Industrial 
Classification System (NAICS) Code.''
    The revisions read as follows:

Appendix F to Part 112--Facility-Specific Response Plan

* * * * *

1.2.7  Current Operation

    Briefly describe the facility's operations and include the North 
American Industrial Classification System (NAICS) code.
* * * * *

1.4.3  Analysis of the Potential for an Oil Discharge

    * * * This analysis shall incorporate factors such as oil 
discharge history, horizontal range of a potential discharge, and 
vulnerability to natural disaster, and shall, as appropriate, 
incorporate other factors such as tank age. * * * The owner or 
operator may need to research the age of the tanks the oil discharge 
history at the facility.
* * * * *

1.7.3  Containment and Drainage Planning

* * * * *
    (7) Other cleanup materials.
    In addition, a facility owner or operator must meet the 
inspection and monitoring requirements for drainage contained in 40 
CFR part 112, subparts A through C. A copy of the containment and 
drainage plans that are required in 40 CFR part 112, subparts A 
through C may be inserted in this section, including any diagrams in 
those plans.

    Note: The general permit for stormwater drainage may contain 
additional requirements.

* * * * *

1.8.1  Facility Self-Inspection

    Under 40 CFR 112.7(e), you must include the written procedures 
and records of inspections for each facility in the SPCC Plan. You 
must include the inspection records for each container, secondary 
containment, and item of response equipment at the facility. You 
must cross-reference the records of inspections of each container 
and secondary containment required by 40 CFR 112.7(e) in the 
facility response plan. The inspection record of response equipment 
is a new requirement in this plan. Facility self-inspection requires 
two-steps: (1) a checklist of things to inspect; and (2) a method of 
recording the actual inspection and its findings. You must note the 
date of each inspection. You must keep facility response plan 
records for five years. You must keep SPCC records for three years.
* * * * *

1.8.1.1.  Tank Inspection

    The tank inspection checklist presented below has been included 
as guidance during inspections and monitoring. Similar requirements 
exist in 40 CFR part 112, subparts A through C. * * *
* * * * *

1.8.1.3  Secondary Containment Inspection

* * * * *
    * * * Similar requirements exist in 40 CFR part 112, subparts A 
through C. * * *
* * * * *

1.10  Security

    According to 40 CFR 112.7(g) facilities are required to maintain 
a certain level of security, as appropriate. * * *
* * * * *

2.1  General Information

* * * * *
    (6) North American Industrial Classification System (NAICS) 
Code: Enter the facility's NAICS code as determined by the Office of 
Management and Budget (this information may be obtained from public 
library resources.)
* * * * *

3.0  Acronyms

* * * * *
    NAICS: North American Industrial Classification System
* * * * *

Attachments to Appendix F

Attachment F-1--Response Plan Cover Sheet

* * * * *

General Information

* * * * *
    North American Industrial Classification System (NAICS) Code:
* * * * *

[FR Doc. 02-16852 Filed 7-16-02; 8:45 am]
BILLING CODE 6560-50-P