[Federal Register Volume 59, Number 123 (Tuesday, June 28, 1994)]
[Unknown Section]
[Page ]
From the Federal Register Online via the Government Publishing Office [www.gpo.gov]
[FR Doc No: 94-15510]


[Federal Register: June 28, 1994]


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Part VII





Department of Transportation





_______________________________________________________________________



Research and Special Programs Administration



_______________________________________________________________________



49 CFR Part 195



Regulatory Review: Hazardous Liquid and Carbon Dioxide Pipeline Safety 
Standards; Final Rule
DEPARTMENT OF TRANSPORTATION

Research and Special Programs Administration

49 CFR Part 195

[Docket PS-127; Amdt. 195-52]
RIN 2137-AC27


Regulatory Review: Hazardous Liquid and Carbon Dioxide Pipeline 
Safety Standards

AGENCY: Research and Special Programs Administration (RSPA), DOT.

ACTION: Final rule.

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SUMMARY: This rulemaking amends miscellaneous hazardous liquid and 
carbon dioxide pipeline safety standards to provide clarity, eliminate 
unnecessary or overly burdensome requirements, and foster economic 
growth. The changes result from the regulatory review RSPA carried out 
in response to the President's directive of January 28, 1992, on 
reducing the burden of government regulation. The changes reduce costs 
in the liquid pipeline industry without compromising safety.

EFFECTIVE DATE: This regulation is effective July 28, 1994. The 
incorporation by reference of certain publications listed in the 
regulations is approved by the Director of the Federal Register as of 
July 28, 1994.

FOR FURTHER INFORMATION CONTACT: J. Willock, (202) 366-2392, regarding 
the subject matter of this final rulemaking, or the Dockets Unit, (202) 
366-5046, regarding copies of this final rulemaking or other material 
that is referenced herein.

SUPPLEMENTARY INFORMATION:

Background

    In a January 28, 1992, memorandum, the President wrote to 
Department and agency heads about the need to reduce the burden imposed 
by government regulation. The President was concerned that agencies 
were not doing enough to review and revise existing regulations to 
eliminate unnecessary and overly burdensome requirements. The President 
recognized that regulations that do not keep pace with new technologies 
and innovations impose needless costs and impede economic growth.
    In response to the President's memorandum, DOT published a notice 
requesting public comment on the Department's regulatory programs (57 
FR 4745; Feb. 7, 1992). Commenters were asked to identify regulations 
that substantially impede economic growth, may no longer be necessary, 
are unnecessarily burdensome, impose needless costs or red tape, or 
overlap or conflict with other DOT or federal regulations. The deadline 
for submitting comments was March 2, 1992.
    RSPA received comments from six organizations about the pipeline 
safety regulations in part 195. Comments were from three regulated 
pipeline companies, a pipeline trade association, a state pipeline 
safety agency, and a federal agency. RSPA considered all comments in 
its review of the regulations, and these comments are available in the 
docket. Some comments will be considered in future rulemakings. 
Additionally, RSPA has published a separate rulemaking ``Update of 
Standards Incorporated by Reference'' (58 FR 14519; March 18, 1993) 
which updates the editions of the industry standards that are 
incorporated in part 195.
    On November 27, 1992, RSPA published a Notice of Proposed 
Rulemaking, NPRM, (57 FR 56304) proposing 18 changes to the regulations 
based on the comments received from the public and asked for further 
comments regarding the proposed changes. RSPA received comments from 21 
organizations: 15 pipeline companies, 3 pipeline trade associations, 2 
environmental organizations, and 1 county government. RSPA considered 
all comments in preparation of the final rulemaking and the comments 
are available in the Docket.

Advisory Committee

    The Technical Hazardous Liquid Pipeline Safety Standards Committee 
(THLPSSC), consisting of 15 members, was established by statute to 
consider the feasibility, reasonableness, and practicability of 
proposed pipeline regulations. RSPA implemented the committee balloting 
process by mail. After initial balloting, the process allowed each 
member to review the ballots, including comments, of all other members, 
and to change his or her vote or initial comment if desired. Although 
some THLPSSC members did not vote on every proposed change, a tally of 
the second ballots showed that a large majority of THLPSSC members 
found all the proposed changes technically feasible, reasonable, and 
practicable. Nonetheless, in developing the final regulations, RSPA 
considered all final THLPSSC votes and comments, including minority 
positions. The following discussion explains how RSPA treated THLPSSC 
positions and public comments on the proposed amendments in developing 
the final rule.

Changes to Part 195 Safety Standards

    The following discussion explains the changes to various standards 
in part 195:

Section 195.1  Applicability.

    Offshore production. Part 195 does not apply to pipelines used in 
offshore production, whether on the Outer Continental Shelf or in state 
offshore waters. However, this exception is clearly stated in part 195 
only for production on the Outer Continental Shelf (Sec. 195.1(b)(5)). 
To clarify that all offshore pipelines used in production are outside 
part 195, RSPA proposed to delete from Sec. 195.1(b)(5) the phrase ``on 
the Outer Continental Shelf''.
    The 10 THLPSSC members who voted on the proposed amendment to 
Sec. 195.1(b)(5) all approved the amendment.
    In addition, RSPA received comments from three operators and two 
pipeline-related associations in support of the amendment and no 
adverse comments. Therefore, Sec. 195.1(b)(5) is amended as proposed in 
the NPRM.
    We also requested comments on whether there is a gap in the 
regulation of production lines in state offshore waters. Only one 
commenter responded. This commenter opined that existing state and 
federal programs adequately regulate production lines in state waters. 
In Louisiana, the Departments of Natural Resources and Environmental 
Quality were said to have comprehensive regulations on facility 
installation, operation, integrity, and removal, and sufficient 
authority to address any ``gap'' that is identified. Since the other 
states with production lines in state waters have similar regulations, 
RSPA does not believe there is a gap in the regulation of production 
lines in state waters.
    In-plant piping. Part 195 does not apply to pipeline transportation 
through onshore production, refining, or manufacturing facilities, or 
storage or in-plant piping systems associated with such facilities 
(Sec. 195.1(b)(6)). Because the physical distinction between a 
regulated pipeline serving a plant and unregulated in-plant piping is 
unclear, RSPA proposed to add a definition of ``in-plant piping 
system'' to Sec. 195.2. The definition proposed was: ``In-plant piping 
system means piping that is located on the grounds of a plant and used 
to transfer hazardous liquid or carbon dioxide between plant facilities 
or between plant facilities and a pipeline, not including any device 
and associated piping that are necessary to control pressure in the 
pipeline.'' The NPRM explained that we would consider in-plant piping 
to extend to the plant boundary in the absence of a necessary pressure 
control device on plant grounds.
    All ten THLPSSC members who voted on this proposal supported it. 
However, four members believed that because the NPRM primarily 
concerned pipeline transportation rather than production, refining, or 
manufacturing plants, it did not give plant owners adequate notice that 
the proposed definition could affect plant piping. These members wanted 
RSPA to publish a separate NPRM on the subject of in-plant piping.
    RSPA does not agree that another NPRM is needed. The subject of in-
plant piping and the associated issues were clearly discussed in the 
published NPRM. Also, all interested persons, including plant owners as 
well as pipeline operators, were given an opportunity to comment on the 
subject of in-plant piping.
    RSPA received comments on the proposed definition from seven 
operators, two pipeline-related associations, and one state agency. Two 
operators and one association fully supported the proposal.
    One operator and a pipeline-related association thought plant 
owners were not adequately notified of the proposed rule, and that RSPA 
should treat the subject in a separate NPRM. Our position on this issue 
is given supra in response to a similar criticism by four THLPSSC 
members.
    Another operator was concerned that the proposed definition would 
cause operator-owned components, such as pipe, meters, instruments, and 
manifolds, that are located on plant grounds downstream from the 
operator's pressure control device to fall outside part 195. The 
operator was worried that other agencies would regulate these 
components as non-transportation related facilities. We are not 
persuaded, however, that the potential for such regulation is 
sufficient reason to exclude the components from the definition of in-
plant piping system. The aim of the proposed definition was to 
distinguish unregulated piping, not to limit the jurisdiction of other 
government agencies.
    In contrast, an operator of gathering and processing facilities was 
concerned that part 195 would apply to plant piping that lies between 
any necessary pressure control device and the connection to a pipeline. 
This commenter apparently did not realize that such piping is subject 
to part 195. RSPA has applied part 195 to such piping because it is 
subject to pressure which is controlled by a device operators must have 
to meet Sec. 195.406(b). However, this application has had little 
effect on plant owners, because we hold the pipeline operator, not the 
plant owner, responsible for compliance.
    An operator commenting on the plant device exclusion in the 
proposed definition advised us to change ``control pressure'' to 
``prevent overpressure.'' This commenter said the change would avoid 
making pipeline operators responsible under part 195 for nonessential 
pressure control devices. We agree the suggested rewording would better 
convey the intent of the proposal. But, in the final definition, we 
have changed ``control pressure in the pipeline'' to ``control pressure 
in the pipeline under Sec. 195.406(b)'' to convey the intent even more 
precisely.
    The state agency commented that if piping on plant grounds does not 
include a device necessary to control pipeline pressure, the 
jurisdiction of part 195 over the pipeline should not end at the plant 
boundary. Instead, the state agency recommended ending jurisdiction at 
a component inside the plant, such as a flange, where the pipeline can 
be isolated for purposes of testing. Although operators may use such 
components, part 195 does not require that they be on the pipeline. 
Also, we believe the plant boundary is a more convenient demarcation of 
in-plant piping than an unspecific inside-the-plant component. Thus, 
the state agency's comment is not incorporated in the final definition.
    The state agency, an operator, and a pipeline-related association 
were concerned that because segments of transfer piping located off 
plant grounds were not included in the proposed definition, a large 
number of short pipelines would come under part 195. RSPA recognizes 
that production, refining, or manufacturing plants often install 
transfer piping off plant grounds. A plant may use this piping to 
transfer hazardous liquids between its different facilities located on 
the same grounds; between its different facilities located on separate 
grounds (usually separated by a roadway, railway, waterway, or 
industrial area); between its facilities and a transportation system, 
such as a railroad or pipeline; or between its facilities and the 
facilities of another plant or industrial consumer. The three 
commenters thought the off-grounds segments should qualify as in-plant 
piping if they connect facilities of the same plant. The association 
also wanted to include under the definition off-grounds segments that 
connect facilities of different plants. In addition, the operator and 
association argued that the off-grounds segments pose minimum risk to 
public safety and the environment, because the segments generally are 
located in industrial areas, roadways, or railways. The association 
further argued that a plant has the same operational control, including 
response capability, over the off-grounds segments as it does over 
piping on plant grounds.
    In response to these comments, we note that Sec. 195.1(b)(6) echoes 
section 201(3) of the Hazardous Liquid Pipeline Safety Act of 1979 
(HLPSA), (49 U.S.C. app. 2001(3)), which excludes certain ``in-plant 
piping systems'' from regulation under the HLPSA. Since neither the 
HLPSA nor its legislative history explain ``in-plant piping,'' we adopt 
an ordinary, reasonable understanding of the term. Therefore, we do not 
accept the interpretation that the term includes piping that crosses 
the property of others outside plant grounds. However, many plants are 
separated by a public thoroughfare, and plant transfer piping crosses 
the thoroughfare. A single public thoroughfare would include any road, 
from a country lane to an interstate highway, but it does not include a 
railroad. Because transfer piping that crosses such thoroughfares is 
comparable in most respects to other in-plant piping, RSPA considers 
the in-plant piping exception to include the thoroughfare crossings. 
The thoroughfare exception does not apply to inter-facility lines or 
delivery lines, because these lines are distinct from in-plant piping. 
We did not intend the proposed definition of ``in-plant piping 
systems'' to expand our present interpretation of the term. So the 
final definition does not incorporate any of the comments concerning 
piping located off plant grounds other than for thoroughfare crossings.
    However, the proposed definition's first use of the term 
``pipeline'' is changed to ``pipeline or other mode of 
transportation.'' This change is needed to include, within the 
definition, piping on plant grounds that transfer hazardous liquid or 
carbon dioxide between plant facilities and modes of transportation 
other than pipeline.
    Terminal facilities. Part 195 does not apply to the transportation 
of hazardous liquid or carbon dioxide by vessel, aircraft, tank truck, 
tank car, or other vehicle, or by terminal facilities used exclusively 
to transfer hazardous liquid or carbon dioxide between such modes of 
transportation (Sec. 195.1(b)(7)). RSPA proposed to amend 
Sec. 195.1(b)(7) to clarify that terminal facilities located off 
terminal grounds are subject to part 195, and to distinguish 
unregulated terminal facilities from a regulated pipeline entering or 
leaving the terminal. As with the proposed in-plant piping definition, 
any device and associated piping on terminal grounds necessary to 
control pressure in a regulated pipeline would not be excepted from 
part 195.
    The THLPSSC voted to approve this proposal, but four members 
believed the NPRM did not give terminal owners adequate notice that the 
proposed amendment could affect their piping. These members wanted RSPA 
to publish a separate NPRM on the subject. For the reasons stated supra 
in response to a similar argument by these THLPSSC members concerning 
in-plant piping, RSPA does not agree that another NPRM is needed.
    Five operators and two pipeline-related associations commented on 
the proposed amendment to Sec. 195.1(b)(7). Of these commenters, two 
operators and one association agreed with the proposal.
    A few commenters expressed the same concerns about the proposed 
amendment to Sec. 195.1(b)(7) as they did about the proposed in-plant 
piping definition. These concerns were that the NPRM did not adequately 
notify plant (terminal) owners of the proposed rule, and that some 
operator-owned components located on plant (terminal) grounds would 
fall outside part 195. Our response to these concerns is the same as 
stated supra regarding in-plant piping.
    In regard to transfer lines located outside terminal grounds at 
ports, an operator and a pipeline-related association pointed out that 
the U.S. Coast Guard regulates transfers between terminal storage and 
dock facilities. These commenters suggested that RSPA and Coast Guard 
develop a memorandum of understanding to limit Coast Guard's 
regulations to dock facilities.
    We recognize that Coast Guard and RSPA jurisdictions overlap in 
port areas, but the two agencies have different responsibilities. Also, 
the overlap does not automatically result in regulatory conflicts, and 
the commenters did not mention any. Nonetheless, though we have not 
changed the final rule as a result of this comment, in enforcing part 
195 at port areas, RSPA will act appropriately to resolve any 
unnecessary regulatory burdens.
    Carbon dioxide injection system. Section 195.1(b)(8) provides that 
part 195 does not apply to ``[t]ransportation of carbon dioxide 
downstream from a point in the vicinity of the well site at which 
carbon dioxide is delivered to a production facility.'' RSPA proposed 
to amend this section to clarify that the exception covers pipelines 
used in the injection of carbon dioxide for oil recovery operations.
    The THLPSSC approved the proposed amendment (10 voted in favor and 
5 did not vote), and we received no adverse comments from the public. 
The proposed amendment to Sec. 195.1(b)(8) is, therefore, adopted as 
final.

Section 195.2  Definitions.

    The proposed revision of the definition of ``Secretary'' is not 
adopted in this rulemaking. Instead, it is being handled in an omnibus 
rulemaking covering all regulations involving pipeline safety.
    The definition of ``In-plant piping system'' is discussed above in 
Sec. 195.1 Applicability.
    Two commenters objected to the proposed definition for petroleum 
products because of its use of the terms ``flammable'', ``toxic'', and 
``corrosive'' which are not defined under part 195. The commenters 
stated that absent specific definitions for these terms, their 
applicability could be unclear.
    RSPA agrees with the comments about the lack of clarity in the 
proposed definition for petroleum products. So, the final rule for this 
section includes new definitions for ``flammable'', ``toxic'', and 
``corrosive'' that come from the definitions contained in 49 CFR part 
173 for Transportation and Packaging of Hazardous Materials for the 
terms ``flammable liquid'', ``poisonous material'', and ``corrosive 
material'', respectively. RSPA has adopted the definition of 
``poisonous material'' for ``toxic'' because it considers the terms 
synonymous.

Sections 195.2, 195.106, 195.112, 195.212 and 195.413  (Nominal Outside 
Diameter of the Pipe in Inches)

    RSPA proposed to standardize the dimensioning of pipe size 
throughout part 195 (Changes are made to Secs. 195.2, 195.106(b), 
195.106(c), 195.112(c), 195.212(b)(3)(ii) and 195.413(a)). All 10 
THLPSSC members who voted were in favor of the proposal and no 
commenter objected thereto. Accordingly, the proposed amendment is 
adopted as final.

Section 195.3  Matter incorporated by reference.

    Section 195.3 sets out the general requirements for the 
incorporation in the regulations of industry standards for the design, 
construction and operation of hazardous liquid and carbon dioxide 
pipelines. Paragraph 195.3(a) states that incorporation of a document 
by reference has the same force as if the document were copied in the 
regulations. Some operators have misinterpreted this section to mean 
that they must comply with all of the terms contained in a referenced 
document. Accordingly, RSPA hereby revises Sec. 195.3(a) to clarify 
that an entire document is not incorporated when the document is 
incorporated by reference; rather, only those portions specifically 
referenced in the regulations are incorporated.
    The rule is being revised to conform to a recent update of 
references in another rulemaking (Update of Standards Incorporated by 
Reference (58 FR 14519; March 18, 1993)). Also, references to ASME/ANSI 
Codes B31.8 and B31.G are being added. The 10 THLPSSC members who voted 
and 7 commenters favored the revision.

Section 195.5  Conversion to service subject to this part.

    Section 195.5 regulates the conversion of steel pipelines to 
hazardous liquid or carbon dioxide service that is subject to part 195. 
Under Sec. 195.5(a)(4), a converted pipeline must be hydrostatically 
tested to substantiate the maximum operating pressure (MOP) permitted 
by Sec. 195.406.\1\
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    \1\Section 195.5(a)(4) actually uses the term ``maximum 
allowable operating pressure,'' but for consistency with 
Sec. 195.406, this term is changed below to MOP by removing the word 
``allowable.''
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    To substantiate the MOP of a converted pipeline, an operator must 
know the pipe design pressure (see current Sec. 195.406(a)(1)). 
Consequently, if pipe design pressure is unknown, a steel pipeline may 
not be converted under Sec. 195.5. Although the design pressure of 
components is an MOP factor under Sec. 195.406(a)(2), pipeline 
components are normally designed to be as strong or stronger than 
attached pipe. Thus, pipe design is the critical factor in 
substantiating MOP under Sec. 195.5(a)(4), and lack of knowledge of 
component design pressure is not a significant safety concern.
    RSPA proposed to amend Sec. 195.5 to permit conversion using an 
approach found in section 845.214 and Appendix N of ASME B31.8 for gas 
pipelines whose design pressure is unknown. Under this proposal, 
operators would pressure test the pipeline under Appendix N until pipe 
yield occurs. Instead of design pressure, this yield test pressure 
would be used to compute MOP by applying certain reduction factors to 
80 percent of the first pressure that produces pipe yield.
    All THLPSSC members who voted on the proposed amendment to 
Sec. 195.5 supported it in concept. However, two members thought the 
wording of Appendix N should be copied directly into part 195 to avoid 
referencing a gas pipeline code in liquid pipeline regulations. We 
believe the principles of Appendix N apply equally to gas and liquid 
pipelines. And since the B31.8 Code is widely used, operators of 
hazardous liquid or carbon dioxide pipelines will not find it difficult 
to obtain and apply Appendix N.
    RSPA received five comments on the proposed amendment to 
Sec. 195.5. Two operators and a pipeline-related association agreed 
with the proposed amendment.
    One operator suggested that if pipelines operating at less than 20 
percent of specified minimum yield strength (SMYS) are subject to 
Sec. 195.5, RSPA should allow operators up to 10 years to meet the 
testing requirements. At present, none of the standards in part 195, 
including Sec. 195.5, applies to pipelines operating at less than 20 
percent of SMYS (see Sec. 195.1(b)(3)). However, this commenter may 
have had in mind Sec. 206 of the Pipeline Safety Act of 1992 (Pub. L. 
102-508), which provides that exceptions to regulations under the 
Hazardous Liquid Pipeline Safety Act of 1979 (49 U.S.C. app. 2001 et 
seq.), such as part 195, may not be based solely on low internal 
stress. Because of this statutory mandate, RSPA has proposed to apply 
part 195 to certain low-stress hazardous liquid pipelines (Docket PS-
117; 58 FR 12213; March 3, 1993). Still, that proposal would not 
require any existing low-stress hazardous liquid pipeline to be tested 
under Sec. 195.5, because such pipelines would not be converted 
pipelines. Of course, if part 195 becomes applicable to low stress 
pipelines, any pipeline converted to low stress hazardous liquid 
service subject to part 195 would have to be tested under Sec. 195.5. 
But, since testing is the backbone of the conversion process, RSPA does 
not believe Sec. 195.5 should be amended to extend the time for testing 
to 10 years.
    A state agency was concerned that if test pressure must be measured 
at the high elevation point of test segments, the test could stress the 
low point of the segment beyond yield. However, the Appendix N test 
method should not result in overstress at the low elevation, because 
the method does not require increases in test pressure after the first 
yield occurs in the test segment.
    In a separate rulemaking proceeding (Docket No. PS-124; 57 FR 
39572; August 31, 1992), RSPA proposed to allow the use of the Appendix 
N method in converting pipelines to gas service under 49 CFR 192.14. 
This gas pipeline conversion standard is similar to Sec. 195.5. 
Comments to that notice argued that pressure testing to yield is 
unnecessary to qualify certain pipelines that operate at low stress 
(generally pipelines 12\3/4\ inches or less in nominal outside diameter 
operating at pressures of 200 psig or less). RSPA believes these 
comments are also relevant to hazardous liquid pipelines. All other 
factors being equal, hazardous liquid pipelines operating at low 
internal stress present less risk of failure from time-dependent 
defects than higher stress hazardous liquid pipelines. Because of the 
lower risk, RSPA has modified the final rule to provide that pipelines 
12\3/4\ inches or less in nominal outside diameter to be operated at a 
pressure of 200 psig or less may be converted without testing to yield. 
The MOP of such pipelines may be determined under Sec. 195.406 by using 
200 psig as pipe design pressure.
    The proposed rule has been redrafted to improve clarity, to better 
relate conversion to design pressure and MOP under Sec. 195.406, and to 
include the changes discussed supra. In the final rule, the proposed 
amendment to Sec. 195.5(a)(1) is revised and published as an amendment 
to Sec. 195.406(a)(1). This latter section deals specifically with pipe 
design pressure and MOP. As set forth infra, revised Sec. 195.406(a)(1) 
provides that when pipe design pressure is unknown for steel pipelines 
being converted, a reduced value of first yield hydrostatic test 
pressure may be used as design pressure to compute MOP. If the pipeline 
to be converted is 12\3/4\ inches or less in nominal outside diameter 
and is not yield tested, 200 psig may be used as design pressure.

Section 195.8  Transportation of hazardous liquid or carbon dioxide in 
pipelines constructed with other than steel pipe.

    The proposal to replace the word ``he'' with ``the Secretary'' to 
remove any implication of gender is not adopted in this rulemaking. 
Instead, this proposal will be handled in an omnibus rulemaking to make 
minor clarifications and error corrections covering all the pipeline 
safety regulations.

Section 195.50  Reporting accidents and Sec. 195.52 Telephonic notice 
of certain accidents.

    Sections 195.50(f) and 195.52(a)(3) require operators to prepare 
reports and give telephonic notice of accidents, respectively, when the 
estimated property damage due to an accident exceeds $5,000. RSPA 
discovered from its regulatory review and previous enforcement cases 
that a significant amount of confusion exists among pipeline operators 
as to which cost estimates must be included in calculating the 
``estimated property damage to the property of the operator or others * 
* *'' Frequently, when reporting accidents, pipeline operators fail to 
include as ``property damage'' the fair market value of the product 
released or those costs associated with clean-up and recovery efforts. 
RSPA believes these costs should be included when reporting accidents.
    Because the $5,000 reporting requirement requires the reporting of 
minor accidents, RSPA proposed amending Secs. 195.50(f) and 
195.52(a)(3) to increase the reporting threshold to $50,000, the same 
level as required in 49 CFR part 192 and to include as property damage 
the value of the product released and the costs associated with clean-
up and recovery efforts. The THLPSSC voted 10 to 0 in favor of the 
change (5 members did not vote). Two of those favoring the proposed 
changes recommended that RSPA modify the final rule to limit property 
damage to fair market value of the lost product and initial clean-up 
and product recovery costs. One member said that clean-up and recovery 
costs should not be included in total property damage.
    Three commenters disagreed with the proposed changes and 
recommended that the rule be withdrawn. One complaint was that the 
statistical base would be discontinuous because, in the future, RSPA 
would not receive information on accidents costing between $5,000 and 
$50,000. Another complaint was that the change could affect the 
development of environmental protection requirements. RSPA understands 
that a change in reporting levels will cause a slight skewing due to 
truncation of the data, but believes requiring operators to report 
accidents based solely on the $5,000 property damage criterion is 
unnecessary and burdensome. Significant accidents will still be 
reported because the other criteria (especially those that are 
environmentally related) requiring reports will be unchanged: (1) 
Explosion or fire, (2) loss of 50 barrels of liquid, (3) escape of five 
barrels a day of highly volatile liquids, (4) a death, (5) bodily harm, 
or (6) resulted in the pollution of any stream. Because these 
requirements remain unchanged, those operators with more frequent small 
releases will still be identified. As to a skewing of the data, those 
organizations that keep track of such statistical data should be able 
to make adjustments to account for such changes. Also, as explained in 
the NPRM, this change will make the liquid safety reporting 
requirements consistent with the gas safety reporting requirements 
which will eliminate confusion. The rule change should have little, if 
any, effect on the environment because the same spill volume reporting 
criteria remain in effect. Only the dollar level of the reporting 
criterion is being changed.
    Two commenters supported the rule changes as they were written. 
Five others favored the changes, but proposed modification of the rules 
to explain more fully the meaning of ``estimated total damage'' in 
order to spell out the items that must be covered. They said that 
``estimated total damage'' is ambiguous and confusing and subject to 
interpretation. One commenter stated that the costs of subsurface 
restoration should be excluded from property damage because it is 
nearly impossible to estimate the subsurface restoration costs within 
the time allowed to report the accident.
    RSPA agrees that early estimates of the costs to clean-up a liquid 
spill may not be exact; however, the operator should, at a later date, 
submit a revised report that provides more reliable cost figures for 
the clean-up.
    RSPA is clarifying the issue by amending Sec. 195.50(f) to read: 
``(f) Estimated property damage, including cost of clean-up and 
recovery, value of lost product, and damage to the property of the 
operator or others, or both, exceeding $50,000'' and Sec. 195.52(a)(3) 
to read: ``(3) Caused estimated property damage, including cost of 
clean-up and recovery, value of lost product, and damage to the 
property of the operator or others, or both, exceeding $50,000.''

Section 195.106  Internal design pressure.

    Section 195.106(a) prescribes the formula for calculating the 
design pressure of steel pipe. In addition, Sec. 195.106(b) regulates 
the pipe yield strength used in the design pressure formula. When the 
specified minimum yield strength (SMYS) of pipe is unknown, 
Sec. 195.106(b) requires that yield strength be derived from tensile 
tests on random samples of pipe. Based on a comparable gas pipeline 
safety standard (49 CFR 192.107(b)(2)), RSPA proposed to amend 
Sec. 195.106(b) to allow operators to use 24,000 psi as yield strength 
if pipe of unknown SMYS is not tensile tested. Editing changes to 
Sec. 195.106(b) were also proposed.
    The 10 THLPSSC members who voted on the proposed amendment of 
Sec. 195.106(b) supported it (5 did not vote). In addition, RSPA 
received comments from four operators and one pipeline-related 
association. The association and three of the operators agreed with the 
proposal. One of these operators suggested further editing, part of 
which RSPA has included in the final rule.
    One operator was concerned that the proposed rule could 
unjustifiably reduce the MOP of its pipelines. The operator said its 
pipelines are made of Grade B pipe (yield strength at least 35,000 psi) 
or better. However, some pipelines may contain pipe for which 
documentation of yield strength or tensile testing does not exist. For 
such pipe, without new tensile testing, yield strength would have to be 
assumed to be 24,000 psi. The operator suggested that RSPA allow 
operators to use appropriate evidence besides tensile tests to 
demonstrate the yield strength of pipe.
    In response to this comment, we note, first, that the proposed 
amendment to Sec. 195.106(b) would not affect the design pressure of 
existing pipelines unless they are replaced, relocated, or otherwise 
changed (see Sec. 195.100). Second, Sec. 195.106(b) currently requires 
operators to use as yield strength either SMYS or a value based on 
tensile testing. So the operator's apparent difficulty in verifying 
yield strength is a problem of compliance with the current rule. Third, 
the proposed rule would relax the burden of tensile testing only when 
MOP does not exceed the level that corresponds to a yield strength of 
24,000 psi. When a higher MOP is desired, operators must use the 
tensile testing option. Finally, RSPA is not aware of any acceptable 
evidence of the yield strength of pipe of unknown SMYS apart from 
appropriate tensile testing. Thus, the amendments to Sec. 195.106(b), 
as discussed above, are adopted.

Section 195.204  Inspection-general.

    The THLPSSC voted 10 to 0 in favor of the proposed change to make 
the language gender neutral and, except for a minor correction, no 
objections were received from commenters. The proposed change is 
adopted as corrected.

Section 195.228  Welds; standards of acceptability.

    One of the comments we received on proposed amendments to 
nondestructive testing requirements under Sec. 195.234(e) (discussed 
infra) concerned the standards for acceptance of weld flaws 
(Sec. 195.228(b)). A pipeline-related association asked us to 
incorporate by reference the alternative acceptance standards for girth 
welds that are in the Appendix to American Petroleum Institute (API) 
Standard 1104 (17th edition). For weld acceptability, Sec. 195.228(b) 
now references the standards in Section 6 of API Standard 1104.
    In a notice of proposed rulemaking involving our review of the gas 
pipeline safety standards in 49 CFR part 192 (Docket PS-124; 57 FR 
39572; August 31, 1992), RSPA proposed to allow gas operators to apply 
the API appendix in addition to section 6 criteria. Although that 
proposal was based on a petition by API to incorporate the appendix by 
reference in both parts 192 and 195, we overlooked the request to 
include such a proposal in the present rulemaking.
    In the part 192 rulemaking, RSPA's gas pipeline safety advisory 
committee voted to support the proposed amendment. Also, all but one of 
the public comments were in favor of allowing use of the Appendix of 
API Standard 1104.
    The dissenting commenter was concerned that industry inspection 
personnel may not be qualified to apply the appendix. However, this 
commenter may not have recognized that under Secs. 192.243(b) and (c), 
operators must ensure that nondestructive testing is performed in 
accordance with written procedures by persons who have been properly 
trained and qualified. Sections 195.234(b) and (c) provide similar 
requirements for nondestructive testing of welds on hazardous liquid 
and carbon dioxide pipelines. RSPA believes these requirements are 
adequate to assure proper application of the appendix.
    The Appendix of API Standard 1104 applies equally to girth welds in 
gas and liquid pipelines. This amendment is not mandatory, rather it 
provides pipeline operators an optional operating procedure. In view of 
the prior opportunity for public comment on use of the appendix for gas 
pipelines, the favorable response by public commenters and RSPA's 
advisory committee, and the fact that use of the appendix would not be 
mandatory, we believe that a further opportunity for public comment is 
unnecessary to allow use of the appendix under Sec. 195.228(b). We feel 
this amendment is a logical outgrowth of the Notice and furthers our 
efforts to make parts 192 and 195 consistent wherever possible. This 
amendment will not have a substantial impact on the regulated 
community.
    Thus, in accordance with 5 U.S.C. 553(b)(3)(B), we are amending 
Sec. 195.228(b) to reference the appendix without further rulemaking 
notice. However, should any person be adversely affected by this 
decision or wish to change the final rule, that person may submit a 
petition for reconsideration under RSPA's rulemaking procedures in 49 
CFR 106.35.
    The final rule provides that the appendix may be used only for 
girth welds to which the appendix applies. For example, as section A.1 
of the appendix states, neither welds in pump stations nor welds used 
to connect fittings and valves are covered by the appendix. Also, the 
appendix applies only to girth welds between pipe of equal nominal wall 
thickness.

Section 195.234  Welds: Nondestructive testing.

    Section 195.234(e) requires that ``100 percent of each day's girth 
welds installed in * * * [certain] locations must be nondestructively 
tested 100 percent unless impracticable, in which case at least 90 
percent must be tested.'' RSPA proposed to amend Sec. 195.234(e) to 
clarify that ``90 percent'' pertains to the number of girth welds that 
must be tested over their entire circumference.
    In addition, Sec. 195.234(g) requires: ``At pipeline tie-ins 100 
percent of the girth welds must be nondestructively tested.'' RSPA 
proposed to clarify that this standard applies to tie-ins of 
replacement sections of pipeline.
    The THLPSSC supported the proposed amendments, although one member 
thought part 195 should define the word ``impracticable.'' We did not 
adopt this recommendation because the word is used in its ordinary 
dictionary sense.
    Three operators and two pipeline-related associations commented on 
the proposed amendments. Three commenters agreed with the proposal, one 
suggested editing changes, and one made a related proposal discussed 
supra under the heading, ``Sec. 195.228(b) Welds; standards of 
acceptability.'' Although we did not adopt all the editing suggestions, 
these comments helped us provide clarity to the final rule.
    In addition, one commenter thought the proposed amendment of 
Sec. 195.234(g) was unnecessary because Sec. 195.200 already indicates 
that Sec. 195.234(g) applies to replacement sections. Moreover, the 
commenter thought adding the proposed phrase to Sec. 195.234(g) would 
create confusion over whether Secs. 195.234(a) through (f) apply to 
replacement sections. While these observations have theoretical merit, 
in practice, some operators have failed to recognize that ``pipeline 
tie-ins'' include tie-ins of replacement sections. The clarifying 
phrase adds emphasis where it is apparently needed to assure compliance 
with the full extent of the rule. Section 195.234(g) is, therefore, 
adopted as proposed.

Sections 195.246  Installation of pipe in a ditch and 195.248 Cover 
over buried pipeline.

    Section 195.246(b) is inconsistent with Sec. 195.413(b)(3) for pipe 
in the Gulf of Mexico and its inlets (See Sec. 195.2 Definitions) under 
water less than 15 feet deep but at least 12 feet deep, because 
Sec. 195.246(b) permits the pipe to be without cover or to be above the 
seabed if properly protected. Such pipe is a ``hazard to navigation'' 
under the definition of that term in Sec. 195.2, and must have the 
minimum cover required by Sec. 195.413(b)(3). In addition, 
Secs. 195.248(a) and (b) are inconsistent with Sec. 195.413(b)(3) for 
pipe in the Gulf of Mexico and its inlets under water less than 12 feet 
deep. Section 195.248(a) allows pipe to be less than 12 inches below 
the seabed (i.e., a hazard to navigation). In certain instances, 
Sec. 195.248(b) allows pipe to be without cover or less than 12 inches 
below the seabed. Neither condition is allowed under 
Sec. 195.413(b)(3). In light of these inconsistences, RSPA proposed in 
the NPRM to amend Secs. 195.246(b) and 195.248(a) and (b) to correct 
the problem.
    Ten THLPSSC members favored the proposed changes (5 members did not 
vote). One of the members favoring the changes said it would make more 
sense to retain the existing regulation which operators have adhered to 
for years. In similar manner, two commenters and one pipeline-related 
organization agreed with the proposal. One commenter and two pipeline-
related organizations disagreed and suggested that references to a 
depth of 15 feet in the rule be eliminated. RSPA proposed changes to 
Secs. 195.246(b), 195.248(a) and 195.248(b) so these sections would 
conform with Public Law 101-599 (section 1, 104 Stat. 3038 (1990)) 
which requires burial of pipe where the subsurface is under 15 feet of 
water as measured from mean low water. Therefore, Secs. 195.246(b), 
195.248(a) and 195.248(b) are adopted as proposed in the NPRM.

Section 195.262  Pumping equipment.

    Section 195.262(d) regulates the location of pumping equipment. The 
rule prohibits the installation of pumping equipment on property not 
under the operator's control. It also prohibits installation less than 
50 feet from the pump station boundary. RSPA proposed to amend 
Sec. 195.262(d) to clarify that these two restraints on location apply 
conjunctively not alternatively.
    The THLPSSC members who voted on the proposed amendment supported 
it in concept, but 5 members recommended further editing of the rule 
for clarity. Although three of the five persons who commented on the 
proposal supported it as proposed, the other two commenters thought 
further clarifying changes were needed. In view of these comments and 
THLPSSC views, we have modified the final rule based on identical 
wording suggested by five THLPSSC members and one commenter.

Section 195.304  Testing of components.

    Section 195.304(b) excludes from hydrostatic testing under part 195 
any component that is the only item being replaced or added to a 
pipeline system if the component or a prototype was tested at the 
factory. RSPA proposed to amend Sec. 195.304(b) to clarify that the 
excluded components do not include pipe.
    The THLPSSC fully supported the proposed amendment. Of the six 
comments from the public on the proposal, a pipeline-related 
association and two operators agreed with it, while three operators 
suggested changes.
    An operator suggested that instead of amending Sec. 195.304(b), we 
should revise the definition of ``component'' to exclude pipe. We did 
not adopt this suggestion because the revision would affect every rule 
in part 195 that uses the term ``component.'' Editing suggested by 
another operator was not adopted because it concerned matters not 
addressed in the NPRM.
    One operator felt pipe should be excluded from hydrostatic testing 
under Sec. 195.304(b) to the same extent as other components. The 
operator said that hydrostatically testing short sections of mill 
tested pipe is duplicative, costly, and not needed for safety. Although 
the NPRM did not propose to alter the existing requirement that 
replacement sections of pipe of any length must be hydrostatically 
tested to part 195 standards before operation, we do not agree with 
this commenter's contention. Normal pipe mill tests are not duplicative 
of part 195 tests, and are not a proven safe alternative to part 195 
requirements. However, for short sections of replacement pipe, part 195 
test requirements could be met anywhere, including, by prior 
arrangement with the operator, in the pipe mill. So if an operator 
wishes to avoid field testing of short replacement sections of pipe, it 
only needs to assure that the mill tests of those sections were done in 
accordance with part 195 test requirements.

Section 195.406  Maximum operating pressure.

    The changes to Sec. 195.406 are discussed supra under Sec. 195.5.

Section 195.412  Inspection of rights-of-way and crossings under 
navigable waters.

    Section 195.412(a) requires an operator, at intervals not exceeding 
3 weeks, but at least 26 times each calendar year, to inspect the 
surface conditions on or adjacent to each pipeline right-of-way. 
Because some surface condition activities that affect the safety and 
operation of pipelines are more visible from aerial patrols than from 
walking or driving the right-of-way, RSPA proposed that the section be 
changed to clarify that aerial patrols are an optional method of 
compliance. No comments were received regarding the change and the 
THLPSSC voted 10 to 0 in favor of the change (5 members did not vote). 
Accordingly, the change to Sec. 195.412(a) is adopted as proposed.
    Section (b) requires operators, at intervals not exceeding 5 years, 
to inspect each crossing under a navigable waterway (except offshore) 
to determine the condition of the crossing. The purpose of the 
inspection is to look for any damage, unanticipated loading, or loss of 
protection that could threaten the safety of the pipeline. We stated in 
the NPRM that bored crossings are usually so deep that there is little 
likelihood the pipeline could be affected by waterway-related events, 
such as scouring or anchor dragging. We proposed to add an exception to 
Sec. 195.412(b) to cover bored crossings that are too deep to be 
subject to waterway-related damage.
    The THLPSSC voted 10 to 0 in favor of the rule (5 members did not 
vote). However, a state pipeline agency suggested the existing 
regulation be retained. The agency stated that a pipeline operator 
cannot be 100 percent sure a bored crossing is so deep it cannot be 
affected as stated. RSPA received four additional comments, three of 
which expressed an opinion that the phrase ``too deep to anticipate 
damage from waterway conditions or vessel traffic'' is vague and 
inappropriate. The other commenter said the proposal is unduly 
restrictive and should be refocused from bored crossings to a more 
generic performance standard potentially including all crossings.
    In view of the comments received, RSPA agrees with those who opined 
that ``too deep to anticipate damage from waterway conditions or vessel 
traffic'' is too vague. In the absence of a recognized standard on the 
subject, it is too speculative to judge when bored crossings are buried 
at a sufficient depth to be safe from damage by external forces. 
Therefore, it is in the interest of public safety that the current rule 
requiring inspection at intervals not exceeding 5 years be retained. 
Accordingly, the proposed change to Sec. 195.412(b) is not adopted.

Section 195.416  External Corrosion Control.

    Section 195.416(a) states that each operator shall, at intervals 
not exceeding 15 months, but at least once each calendar year, conduct 
tests on each underground facility that is under cathodic protection to 
determine whether protection is adequate. RSPA is clarifying the rule 
to reduce any misunderstanding regarding what is meant by 
``underground.'' The word ``underground'' in this paragraph has meant 
any facility that is buried or in contact with the ground. This rule 
clarification will not change the burden on operators because RSPA 
compliance inspectors have consistently required any facility in 
contact with the ground to be cathodically protected.
    RSPA received two comments regarding the change to Sec. 195.416(a). 
One commenter recommended that offshore pipelines be excluded from 
annual testing requirements. RSPA believes there is no acceptable 
substitute for regular testing to determine if corrosion protection of 
all lines, both onshore and offshore, is adequate. Accordingly, ``in 
contact with the ground or submerged'' is added to the rule to assure 
that all underwater pipelines, both onshore and offshore, are included 
in the definition. The other commenter suggested requiring the testing 
of ``carrier pipes'' in casings. ``Carrier pipes'' are normally buried 
and subject to the rule. The THLPSSC voted 10 to 0 in favor of the 
proposed change (5 members did not vote). The revision to 
Sec. 195.416(a) is adopted as modified.
    Section 195.416(f) requires that any pipe found to be generally 
corroded so that the remaining wall thickness is less than the minimum 
thickness required by the pipe specification tolerances must either be 
replaced with coated pipe that meets the requirements of part 195 or, 
if the area is small, must be repaired. However, the operator need not 
replace generally corroded pipe if the operating pressure is reduced to 
be commensurate with the limits on operating pressure specified in 
Sec. 195.406, based on the actual remaining wall thickness.
    Section 195.416(g) states that if localized corrosion pitting is 
found to exist to a degree where leakage might result, the pipe must be 
replaced or repaired, or the operating pressure must be reduced 
commensurate with the strength of the pipe based on the actual 
remaining wall thickness in the pits.
    RSPA recognizes that paragraphs (f) and (g) do not provide guidance 
for an operator's use in determining the strength of the actual 
remaining wall thickness of corroded steel pipe. To provide such 
guidance, RSPA proposed amending Sec. 195.416(h) to adopt the ASME 
Manual B31G procedure for determining the remaining strength of 
corroded steel pipe in existing pipelines. Application of the procedure 
was proposed to be in accordance with the limitations set out in the 
B31G Manual. The rule would provide guidance as to whether a corroded 
region (not penetrating the pipe wall) may be left in service; this 
option might require a reduction in maximum allowable operating 
pressure, but may be more economical than replacement or repair of the 
corroded pipe.
    Ten THLPSSC members voted for the proposal (5 members did not 
vote).
    Comments relative to Sec. 195.416(h) were received from five 
commenters. One commenter said the proposal to change Sec. 195.416(h) 
is inappropriate and should be redone to be consistent with 
Sec. 192.485. Others stated that the proposal was unnecessarily 
restrictive because it did not allow the use of other proven industry 
developed methods for determining the remaining strength of corroded 
pipelines. The most noteworthy method mentioned was ``A Modified 
Criterion for Evaluating the Remaining Strength of Corroded Pipe (with 
RSTRENG disk)'' developed by Battelle under the Pipeline Research 
Committee of the American Gas Association (AGA). (Project PR 3-805, 
December 1989, AGA catalog No. L51609). Project PR 3-805 was undertaken 
to devise a modified criterion that, while still assuring pipeline 
integrity, would eliminate as much as possible the excessive 
specifications embodied in the ASME B31G manual. The AGA modified 
criterion, using a complex analysis approach, can be carried out by 
means of a PC-based program called RSTRENG. The modified criterion can 
also be applied via tables or curves or a long-hand equation if a 
simplified analysis is preferred.
    The addition of the modified criterion to the rule does not 
compromise safety because it merely accepts an established pipeline 
industry guideline, and does not impose new requirements on the 
operators. Accordingly, RSPA is amending Sec. 195.416(h) to include the 
AGA/Battelle--A Modified Criterion for Evaluating the Remaining 
Strength of Corroded Pipe (with the computer disk RSTRENG).

Rulemaking Analyses

Impact Assessment

    This final rule is not considered a significant regulatory action 
under section 3(f) of Executive Order 12866 and, therefore, was not 
subject to review by the Office of Management and Budget. The rule is 
not considered significant under the regulatory policies and procedures 
of the Department of Transportation (44 FR 11034).
    A Regulatory Evaluation has been prepared and is available in the 
docket. RSPA estimates the proposed changes to existing rules would 
result in an estimated savings of $1,534,000 per year for the hazardous 
liquid pipeline industry at no cost to the industry, and with no 
adverse effect on safety. As discussed above, these savings would come 
largely from the use of new technology, greater flexibility in 
constructing and operating pipelines, and the elimination of 
unnecessary requirements.

Federalism Assessment

    RSPA has analyzed the proposed rules under the criteria of 
Executive Order 12612 (52 FR 41685; October 30, 1987). The regulations 
have no substantial effects on the states, on the current federal-state 
relationship, or on the current distribution of power and 
responsibilities among the various levels of government. Thus, 
preparation of a federalism assessment is not warranted.

Regulatory Flexibility Act

    RSPA criteria for small companies or entities are those with less 
than $1,000,000 in revenues and are independently owned and operated. 
Few of the companies subject to this rulemaking meet these criteria. 
Accordingly, based on the facts available concerning the impact of this 
proposal, I certify under Section 605 of the Regulatory Flexibility Act 
that this proposal would not have a significant economic impact on a 
substantial number of small entities. This rule applies to intrastate 
and interstate pipeline facilities used in the transportation of 
hazardous liquids or carbon dioxide.

Paperwork Reduction Act

    The documentation for the information collection requirements for 
part 195 was submitted to the Office of Management and Budget (OMB) 
during the original rulemaking processes. Currently, regulations in 
part 195 are covered by OMB Control Numbers 2137-0047 (approved through 
May 31, 1994), 2137-0578 (approved through October 31, 1994) and 2137-
0583 (approved through May 31, 1994). There are no new information 
collection requirements in this final rule.

List of Subjects in 49 CFR Part 195

    Ammonia, Carbon dioxide, Incorporation by reference, Petroleum, 
Pipeline safety, Reporting and recordkeeping requirements.

    In consideration of the foregoing, RSPA is amending 49 CFR part 195 
as follows:

PART 195--[AMENDED]

    1. The authority citation for part 195 continues to read as 
follows:

    Authority: 49 app. U.S.C. 2002 and 2015; and 49 CFR 1.53.

    2. In Sec. 195.1, the introductory text of paragraph (b) is 
republished, paragraph (b)(5) is revised, in paragraph (b)(6) a hyphen 
is added between the words ``in'' and ``plant'', and paragraphs (b)(7) 
and (b)(8) are revised to read as follows:


Sec. 195.1  Applicability.

* * * * *
    (b) This part does not apply to--
* * * * *
    (5) Transportation of hazardous liquid or carbon dioxide in 
offshore pipelines which are located upstream from the outlet flange of 
each facility where hydrocarbons or carbon dioxide are produced or 
where produced hydrocarbons or carbon dioxide are first separated, 
dehydrated, or otherwise processed, whichever facility is farther 
downstream;
* * * * *
    (7) Transportation of hazardous liquid or carbon dioxide--
    (i) By vessel, aircraft, tank truck, tank car, or other non-
pipeline mode of transportation; or
    (ii) Through facilities located on the grounds of a materials 
transportation terminal that are used exclusively to transfer hazardous 
liquid or carbon dioxide between non-pipeline modes of transportation 
or between a non-pipeline mode and a pipeline, not including any device 
and associated piping that are necessary to control pressure in the 
pipeline under Sec. 195.406(b); and
    (8) Transportation of carbon dioxide downstream from the following 
point, as applicable:
    (i) The inlet of a compressor used in the injection of carbon 
dioxide for oil recovery operations, or the point where recycled carbon 
dioxide enters the injection system, whichever is farther upstream; or
    (ii) The connection of the first branch pipeline in the production 
field that transports carbon dioxide to injection wells or to headers 
or manifolds from which pipelines branch to injection wells.
* * * * *
    3. In Sec. 195.2, the introductory text is republished, definitions 
for Corrosive product, Flammable product, In-plant piping system, 
Petroleum, Petroleum product, and Toxic product are added in 
alphabetical order to read as follows:


Sec. 195.2  Definitions.

    As used in this part--
* * * * *
    Corrosive product means ``corrosive material'' as defined by 
Sec. 173.136 Class 8-Definitions of this chapter.
* * * * *
    Flammable product means ``flammable liquid'' as defined by 
Sec. 173.120 Class 3-Definitions of this chapter.
* * * * *
    In-plant piping system means piping that is located on the grounds 
of a plant and used to transfer hazardous liquid or carbon dioxide 
between plant facilities or between plant facilities and a pipeline or 
other mode of transportation, not including any device and associated 
piping that are necessary to control pressure in the pipeline under 
Sec. 195.406(b).
* * * * *
    Petroleum means crude oil, condensate, natural gasoline, natural 
gas liquids, and liquefied petroleum gas.
    Petroleum product means flammable, toxic, or corrosive products 
obtained from distilling and processing of crude oil, unfinished oils, 
natural gas liquids, blend stocks and other miscellaneous hydrocarbon 
compounds.
* * * * *
    Toxic product means ``poisonous material'' as defined by 
Sec. 173.132 Class 6, Division 6.1-Definitions of this chapter.


Secs. 195.2, 195.112, 195.212, 195.413  [Amended]

    4. In the list below, for each section indicated in the left 
column, the phrase indicated in the middle column is removed and the 
phrase indicated in the right column is added: 

----------------------------------------------------------------------------------------------------------------
              Section                                Remove                                  Add                
----------------------------------------------------------------------------------------------------------------
195.2, Gathering line...............  8 inches or less in nominal diameter  219.1 mm (8\5/8\ in) or less nominal
                                                                             outside diameter.                  
195.112(c)..........................  An outside diameter of 4 inches or    A nominal outside diameter of 114.3 
                                       more.                                 mm (4\1/2\ in) or more.            
195.212(b)(3)(ii)...................  The pipe is 12 inches or less in      The pipe is 323.8 mm (12\3/4\ in) or
                                       outside diameter.                     less nominal outside diameter.     
195.413(a)..........................  Except for gathering lines of 4-inch  Except for gathering lines of 114.3 
                                       nominal diameter or smaller.          mm (4\1/2\ in) nominal outside     
                                                                             diameter or smaller.               
----------------------------------------------------------------------------------------------------------------

    5. In Sec. 195.3, paragraph (a) is revised to read as follows:


Sec. 195.3  Matter incorporated by reference.

    (a) Any document or portion thereof incorporated by reference in 
this part is included in this part as though it were printed in full. 
When only a portion of a document is referenced, then this part 
incorporates only that referenced portion of the document and the 
remainder is not incorporated. Applicable editions are listed in 
paragraph (c) of this section in parentheses following the title of the 
referenced material. Earlier editions listed in previous editions of 
this section may be used for components manufactured, designed, or 
installed in accordance with those earlier editions at the time they 
were listed. The user must refer to the appropriate previous edition of 
49 CFR for a listing of the earlier editions.
* * * * *
    6. In Sec. 195.3, paragraphs (b)(1) through (b)(5) are redesignated 
as paragraphs (b)(2) through (b)(6) and paragraph (b)(1) is added to 
read as follows:


Sec. 195.3  Matter incorporated by reference.

* * * * *
    (b) * * *
    (1) American Gas Association (AGA), 1515 Wilson Boulevard, 
Arlington, VA 22209.
* * * * *
    7. In Sec. 195.3, paragraphs (c)(2)(iii) and (c)(2)(iv) are 
redesignated as paragraphs (c)(2)(v) and (c)(2)(vi) and paragraphs 
(c)(2)(iii) and (c)(2)(iv) are added to read as follows:


Sec. 195.3  Matter incorporated by reference.

* * * * *
    (c) * * *
    (2) * * *
    (iii) ASME/ANSI B31.8 ``Gas Transmission and Distribution Piping 
Systems'' (1989 with ASME/ANSI B31.8a-1990, B31.8b-1990, B31.8c-1992 
Addenda and Special Errata issued July 6, 1990 and Special Errata 
(Second) issued February 28, 1991).
    (iv) ASME/ANSI B31G, ``Manual for Determining the Remaining 
Strength of Corroded Pipelines'' (1991).
* * * * *
    8. In Sec. 195.3, paragraphs (c)(1) through (c)(4) are redesignated 
as paragraphs (c)(2) through (c)(5) and paragraph (c)(1) is added to 
read as follows:


Sec. 195.3  Matter incorporated by reference.

* * * * *
    (c) * * *
    (1) American Gas Association (AGA): AGA Pipeline Research 
Committee, Project PR-3-805, ``A Modified Criterion for Evaluating the 
Remaining Strength of Corroded Pipe'' (December 1989). The RSTRENG 
program may be used for calculating remaining strength.
* * * * *
    9. Section 195.5 is amended by revising paragraphs (a)(1) and 
(a)(4) to read as follows:


Sec. 195.5  Conversion to service subject to this part.

    (a) * * *
    (1) The design, construction, operation, and maintenance history of 
the pipeline must be reviewed and, where sufficient historical records 
are not available, appropriate tests must be performed to determine if 
the pipeline is in satisfactory condition for safe operation. If one or 
more of the variables necessary to verify the design pressure under 
Sec. 195.106 or to perform the testing under paragraph (a)(4) of this 
section is unknown, the design pressure may be verified and the maximum 
operating pressure determined by--
    (i) Testing the pipeline in accordance with ASME B31.8, Appendix N, 
to produce a stress equal to the yield strength; and
    (ii) Applying, to not more than 80 percent of the first pressure 
that produces a yielding, the design factor F in Sec. 195.106(a) and 
the appropriate factors in Sec. 195.106(e).
* * * * *
    (4) The pipeline must be tested in accordance with subpart E of 
this part to substantiate the maximum operating pressure permitted by 
Sec. 195.406.
* * * * *
    10. Section 195.50(f) is revised to read as follows:


Sec. 195.50  Reporting accidents.

* * * * *
    (f) Estimated property damage, including cost of clean-up and 
recovery, value of lost product, and damage to the property of the 
operator or others, or both, exceeding $50,000.
    11. Section 195.52(a)(3) is revised to read as follows:


Sec. 195.52  Telephonic notice of certain accidents.

    (a) * * *
    (3) Caused estimated property damage, including cost of cleanup and 
recovery, value of lost product, and damage to the property of the 
operator or others, or both, exceeding $50,000;
* * * * *
    12. Section 195.106(b) is revised to read as follows:


Sec. 195.106  Internal design pressure.

* * * * *
    (b) The yield strength to be used in determining the internal 
design pressure under paragraph (a) of this section is the specified 
minimum yield strength. If the specified minimum yield strength is not 
known, the yield strength to be used in the design formula is one of 
the following:
    (1)(i) The yield strength determined by performing all of the 
tensile tests of API Specification 5L on randomly selected specimens 
with the following number of tests: 

------------------------------------------------------------------------
             Pipe size                           No. of tests           
------------------------------------------------------------------------
Less than 168.3 mm (6\5/8\ in)       One test for each 200 lengths.     
 nominal outside diameter.                                              
168.3 through 323.8 mm (6\5/8\       One test for each 100 lengths.     
 through 12\3/4\ in) nominal                                            
 outside diameter.                                                      
Larger than 323.8 mm (12\3/4\ in)    One test for each 50 lengths.      
 nominal outside diameter.                                              
------------------------------------------------------------------------

    (ii) If the average yield-tensile ratio exceeds 0.85, the yield 
strength shall be taken as 165,474 kPa (24,000 psi). If the average 
yield-tensile ratio is 0.85 or less, the yield strength of the pipe is 
taken as the lower of the following:
    (A) Eighty percent of the average yield strength determined by the 
tensile tests.
    (B) The lowest yield strength determined by the tensile tests.
    (2) If the pipe is not tensile tested as provided in paragraph (b) 
of this section, the yield strength shall be taken as 165,474 kPa 
(24,000 psi).
* * * * *
    13. In Sec. 195.106(c), the last sentence is revised to read as 
follows:


Sec. 195.106  Internal design pressure.

* * * * *
    (c) * * * However, the nominal wall thickness may not be more than 
1.14 times the smallest measurement taken on pipe that is less than 508 
mm (20 in) nominal outside diameter, nor more than 1.11 times the 
smallest measurement taken on pipe that is 508 mm (20 in) or more in 
nominal outside diameter.
* * * * *
    14. In Sec. 195.204, the last sentence is revised to read as 
follows:


Sec. 195.204  Inspection--general.

    * * * No person may be used to perform inspections unless that 
person has been trained and is qualified in the phase of construction 
to be inspected.
    15. Section 195.228(b) is revised to read as follows:


Sec. 195.228  Welds and welding inspection: Standards of acceptability.

* * * * *
    (b) The acceptability of a weld is determined according to the 
standards in section 6 of API Standard 1104. However, if a girth weld 
is unacceptable under those standards for a reason other than a crack, 
and if the Appendix to API Standard 1104 applies to the weld, the 
acceptability of the weld may be determined under that appendix.
    16. Section 195.234 is amended by revising the introductory text of 
paragraph (e) and by revising paragraph (g) to read as follows:


Sec. 195.234  Welds: Nondestructive testing.

* * * * *
    (e) All girth welds installed each day in the following locations 
must be nondestructively tested over their entire circumference, except 
that when nondestructive testing is impracticable for a girth weld, it 
need not be tested if the number of girth welds for which testing is 
impracticable does not exceed 10 percent of the girth welds installed 
that day:
* * * * *
    (g) At pipeline tie-ins, including tie-ins of replacement sections, 
100 percent of the girth welds must be nondestructively tested.
    17. Section 195.246 is amended by revising paragraph (b) to read as 
follows:


Sec. 195.246  Installation of pipe in a ditch.

* * * * *
    (b) Except for pipe in the Gulf of Mexico and its inlets, all 
offshore pipe in water at least 3.7 m 12-ft-deep but not more than 61 m 
(200 ft) deep, as measured from the mean low tide, must be installed so 
that the top of the pipe is below the natural bottom unless the pipe is 
supported by stanchions, held in place by anchors or heavy concrete 
coating, or protected by an equivalent means.
    18. Section 195.248 is amended by revising in the first column of 
the table in paragraph (a) the language ``Other offshore areas under 
water less than 12-ft-deep as measured from the mean low tide'' to read 
``Gulf of Mexico and its inlets and other offshore areas under water 
less than 12-ft-deep as measured from the mean low tide'' and by 
revising the introductory text of paragraph (b) to read as follows:


Sec. 195.248  Cover over buried pipeline.

* * * * *
    (b) Except for the Gulf of Mexico and its inlets, less cover than 
the minimum required by paragraph (a) of this section and Sec. 195.210 
may be used if--
* * * * *
    19. Section 195.262(d) is revised to read as follows:


Sec. 195.262  Pumping equipment.

* * * * *
    (d) Except for offshore pipelines, pumping equipment must be 
installed on property that is under the control of the operator and at 
least 15.2 m (50 ft) from the boundary of the pump station.
* * * * *
    20. The introductory text of Sec. 195.304(b) is revised to read as 
follows:


Sec. 195.304  Testing of components.

* * * * *
    (b) A component, other than pipe, that is the only item being 
replaced or added to the pipeline system need not be hydrostatically 
tested under paragraph (a) of this section if the manufacturer 
certifies that either--
* * * * *
    21. Section 195.406 is amended by republishing the introductory 
text of paragraph (a) and revising paragraph (a)(1) to read as follows:


Sec. 195.406  Maximum operating pressure.

    (a) Except for surge pressures and other variations from normal 
operations, no operator may operate a pipeline at a pressure that 
exceeds any of the following:
    (1) The internal design pressure of the pipe determined in 
accordance with Sec. 195.106. However, for steel pipe in pipelines 
being converted under Sec. 195.5, if one or more factors of the design 
formula (Sec. 195.106) are unknown, one of the following pressures is 
to be used as design pressure:
    (i) Eighty percent of the first test pressure that produces yield 
under section N5.0 of Appendix N of ASME B31.8, reduced by the 
appropriate factors in Secs. 195.106 (a) and (e); or
    (ii) If the pipe is 323.8 mm (12\3/4\ in) or less outside diameter 
and is not tested to yield under this paragraph, 1379 kPa (200 psig).
* * * * *
    22. Section 195.412(a) is revised to read as follows:


Sec. 195.412  Inspection of rights-of-way and crossings under navigable 
waters.

    (a) Each operator shall, at intervals not exceeding 3 weeks, but at 
least 26 times each calendar year, inspect the surface conditions on or 
adjacent to each pipeline right-of-way. Methods of inspection include 
walking, driving, flying or other appropriate means of traversing the 
right-of-way.
* * * * *
    23. Section 195.416 is amended by revising paragraph (a), 
redesignating paragraph (h) as paragraph (i) and adding a new paragraph 
(h) to read as follows:


Sec. 195.416  External corrosion control.

    (a) Each operator shall, at intervals not exceeding 15 months, but 
at least once each calendar year, conduct tests on each buried, in 
contact with the ground, or submerged pipeline facility in its pipeline 
system that is under cathodic protection to determine whether the 
protection is adequate.
* * * * *
    (h) The strength of the pipe, based on actual remaining wall 
thickness, for paragraphs (f) and (g) of this section may be determined 
by the procedure in ASME B31G manual for Determining the Remaining 
Strength of Corroded Pipelines or by the procedure developed by AGA/
Battelle--A Modified Criterion for Evaluating the Remaining Strength of 
Corroded Pipe (with RSTRENG disk). Application of the procedure in the 
ASME B31G manual or the AGA/Battelle Modified Criterion is applicable 
to corroded regions (not penetrating the pipe wall) in existing steel 
pipelines in accordance with limitations set out in the respective 
procedures.
* * * * *
    Issued in Washington, DC, on June 9, 1994.
Ana Sol Gutierrez,
Acting Administrator, Research and Special Programs Administration.
[FR Doc. 94-15510 Filed 6-27-94; 8:45 am]
BILLING CODE 4910-60-P