56442 Federal Register / Vol. 72, No. 191 / Wednesday, October 3, 2007 / Proposed Rules 

DEPARTMENT OF THE INTERIOR 

Minerals Management Service 

30 CFR Parts 250, 253, 254, 256 

RIN 1010–AD11 

Oil and Gas and Sulphur Operations in 

the Outer Continental Shelf—Pipelines 

and Pipeline Rights-of-Way 

AGENCY: Minerals Management Service 

(MMS), Interior. 

ACTION: Proposed rule. 

SUMMARY: This proposed rulemaking 

completely revises the MMS Outer 

Continental Shelf pipeline and pipeline 

Rights-of-Way (ROW) regulations, and 

brings them up to date with current 

industry practices and technology. The 

proposed rule incorporates parts of 

several new and revised industry 

standards into the regulations. It also 

incorporates several conditions of 

approval for pipelines, plus guidance 

from various Notices to Lessees and 

Operators (NTLs) and one Letter to 

Lessees and Operators (LTL) into one set 

of comprehensive pipeline regulations. 

The proposed regulations would 

eliminate several NTLs and the LTL, 

and have been rewritten in plain 

language. 

DATES: Submit comments by January 31, 

2008. The MMS may not fully consider 

comments received after this date. 

Submit comments to the Office of 

Management and Budget on the 

information collection burden in this 

proposed rule by November 2, 2007. 

ADDRESSES: You may submit comments 

on the proposed rulemaking by any of 

the following methods. Please use the 

Regulation Identifier Number (RIN) 

1010–AD11 as an identifier in your 

message. See also Public Availability of 

Comments under Procedural Matters. 

• Federal eRulemaking Portal: http:// 

www.regulations.gov. Follow the 

instructions on the Web site for 

submitting comments. 

• E-mail MMS at 

rules.comments@mms.gov. Use RIN 

1010–AD11 in the subject line. 

• Fax: 703–787–1546. Identify with 

the RIN, 1010–AD11. 

• Mail or hand-carry comments to the 

Department of the Interior; Minerals 

Management Service; Attention: 

Regulations and Standards Branch 

(RSB); 381 Elden Street, MS–4024; 

Herndon, Virginia 20170–4817. Please 

reference ‘‘Pipelines and Pipeline 

Rights-of-way, 1010–AD11’’ in your 

comments and include your name and 

return address. 

• Send comments on the information 

collection in this rule to: Interior Desk 

Officer 1010–0050, Office of 

Management and Budget, 202–395–6566 

(fax); e-mail: oira_docket@omb.eop.gov. 

Please also send a copy to MMS. 

FOR FURTHER INFORMATION CONTACT: For 

comments or questions on procedural 

issues, contact Richard Ensele, 

Regulations and Standards Branch, 703– 

787–1583. For questions on technical 

issues, contact Alex Alvarado, Pipeline 

Section, Gulf of Mexico Outer 

Continental Shelf Region, 504–736– 

2547. 

SUPPLEMENTARY INFORMATION: The 

proposed rule is a complete revision of 

the regulations regarding pipelines and 

pipeline ROWs on the Outer 

Continental Shelf (OCS). The current 

regulations were originally published on 

April 1, 1988; various sections have 

been updated, and MMS has issued 

several NTLs and one LTL to clarify the 

regulations and to provide guidance. In 

addition, MMS often uses ‘‘conditions 

of approval’’ when approving pipeline 

applications to ensure that pipelines are 

installed, operated, maintained, and 

repaired in a safe and environmentally 

sound manner. The proposed rule 

incorporates some of those conditions of 

approval, and the guidance from the 

following NTLs and LTL (these 

documents are available on the MMS 

Web site at http://www.mms.gov/ntls/): 

• NTL No. 2007–G09, Air Emissions 

Information for Applications for 

Accessory Platforms to Pipeline Rightsof-way (would be eliminated by the 

proposed rule); 

• NTL No. 98–09, Proposed and AsBuilt Pipeline Location Data (would be 

eliminated by the proposed rule); 

• NTL No. 2007–G01, Shallow 

Hazards Requirements; 

• NTL No. 2000–G20, Deepwater 

Chemosynthetic Communities; 

• NTL No. 2002–G03, Supervisory 

Control and Data Acquisition (SCADA) 

Systems; 

• NTL No. 2007–G20, Coastal Zone 

Management Program Requirements for 

OCS ROW Pipeline Applications (would 

be eliminated by the proposed rule); 

• NTL No. 2004–G05, Biologically 

Sensitive Areas of the Gulf of Mexico; 

• NTL No. 2005–G07, Archaeological 

Resource Surveys and Reports; 

• NTL No. 2007–G14, Pipeline Risers 

Subject to the Platform Verification 

Program (would be eliminated by the 

proposed rule); and 

• LTL dated April 18, 1991, Provide 

Clarification, Description, and 

Interpretation with Regard to Pipeline 

Requirements (would be eliminated by 

the proposed rule). 

One of the goals in the proposed rule 

is to minimize the use of conditions of 

approval and NTLs. By incorporating 

this information, we hope to eliminate 

most of the conditions of approval, the 

four NTLs as noted above, and the LTL 

listed above. The remaining five NTLs 

would remain in effect, since they apply 

to other operations in addition to 

pipelines. In most cases, the industry 

has complied with these conditions and 

followed the guidance in the NTLs for 

several years. Even though these 

requirements are new to the regulations, 

they are generally not new to the 

industry. 

Another goal of the proposed rule is 

to update several industry standards 

already incorporated by reference into 

the regulations, and to incorporate new 

standards which would give the 

industry more options in designing new 

pipelines. 

Review of Proposed Rule 

The proposed revision of subpart J is 

much longer than the current 

regulations in subpart J. It is more 

comprehensive, clear, and detailed. 

Most of the changes are designed to 

enhance safety and protect the 

environment. Many of the changes are 

based on American Petroleum Institute 

(API), American National Standards 

Institute (ANSI), and American Society 

of Mechanical Engineers (ASME) 

recommended practices, as well as 

standard MMS and industry practices. 

MMS will discuss the more significant 

changes here. 

The proposed rule revises several of 

the definitions in § 250.105. The 

definitions in § 250.105 that MMS 

proposes to revise appear in other 

subparts as well as subpart J. Terms 

used only in subpart J are defined in 

proposed § 250.1000 if the term is used 

in more than one place in subpart J. If 

a term is used in only one place in 

subpart J, it is defined in place. 

The proposed rule uses standards 

incorporated by reference applicable to 

pipelines. In some cases, MMS decided 

to include only the applicable language 

from a standard in the rule, rather than 

incorporate the entire standard. In other 

instances, MMS incorporated the 

standard or updated the currently 

incorporated standard. MMS will 

address the specific standards as they 

appear in the proposed rule. Since all 

documents incorporated by reference 

are covered under 30 CFR 250 subpart 

A at § 250.198, MMS proposes to update 

this section to include any new or 

changed documents. This includes 

revising the citations listed for several 

currently incorporated documents to 

correspond to the proposed subpart J 

rulemaking. MMS also added and 

changed requirements that relate to OCS 


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Federal Register / Vol. 72, No. 191 / Wednesday, October 3, 2007 / Proposed Rules 56443 

pipelines contained in 30 CFR parts 

253, Oil Spill Financial Responsibility; 

254, Oil Spill Response Requirements 

for Facilities Located Seaward of the 

Coastline; and 256, Leasing of Sulphur 

or Oil or Gas in the Outer Continental 

Shelf. 

MMS has divided the proposed rule 

into several broad subject categories as 

follows: 

• General 

• Applications for New Pipelines 

• Pipeline Application Contents 

• Pipeline Design 

• Pipeline Fabrication 

• Pipeline Construction 

• Pipeline Risers Connected to Floating 

Platforms 

• Pipeline Pressure Testing 

• Pipeline Safety Equipment 

• Pipeline Leak Detection 

• Pipeline Internal Corrosion Control 

and Flow Assurance 

• Pipeline Operations and Maintenance 

• Pipeline Modifications and Repairs 

• Pipeline Surveying, Monitoring, and 

Inspection 

• Pipeline Decommissioning 

• Pipeline Right-of-way (ROW) Grants 

• Accessories to Right-of-way (ROW) 

Pipelines 

The following is an overview of each 

category, and a discussion of the 

significant changes and requirements. 

General 

The General category covers 

definitions, general requirements, types 

of pipelines, jurisdiction, and a table 

that summarizes required applications, 

notifications, plans, and reports. The 

definitions used in this rulemaking have 

been discussed above. MMS considered 

adding a listing or table of acronyms 

after the definitions section, but decided 

against that due to the length of this 

proposed subpart. Would it be helpful 

to include such a listing or table? 

The proposed rule provides the basic 

regulations for OCS pipelines. There are 

other laws, conditions, and stipulations 

that apply to pipelines on the OCS 

which are not mentioned in the current 

regulations, but are addressed in this 

proposed rule. They include: 

• OCS Lands Act (OCSLA), as amended 

• National Environmental Policy Act 

(NEPA) 

• Coastal Zone Management Act 

(CZMA) 

• Oil Pollution Act of 1990 (OPA 90) 

• Federal Water Pollution Control Act 

(FWPCA) 

• Applicable implementing regulations 

• Approved applications 

• Development Operations 

Coordination Documents (DOCD) 

• Development and Production Plans 

(DPP) 

• Lease provisions and stipulations 

The Department of the Interior (DOI), 

through MMS, is one of two Federal 

agencies with jurisdiction over OCS oil 

and gas pipelines. The other is the U.S. 

Department of Transportation (DOT). 

Jurisdictional issues between the two 

agencies are addressed in this category. 

The jurisdictional criteria are based on 

the December 1996 Memorandum of 

Understanding (MOU) between DOI and 

DOT. According to the MOU, produceroperated pipelines are generally under 

DOI jurisdiction, and transporteroperated pipelines are generally under 

DOT jurisdiction. The MOU includes 

the flexibility to cover situations that do 

not correspond to its general definition 

of the jurisdictional boundary as ‘‘the 

point at which operating responsibility 

transfers from a producing operator to a 

transporting operator.’’ The MOU also 

provides that DOI and DOT may, 

through their enforcement agencies and 

in consultation with the affected parties, 

agree to exceptions to the MOU on a 

facility-by-facility or area-by-area basis. 

Operators may also petition DOI and 

DOT for exceptions to the MOU. 

This category includes a table that 

summarizes the various applications, 

notifications, plans, and reports that a 

company must submit to MMS, 

including the timing of the submittal or 

notification and the number of copies 

required. 

Applications for New Pipelines 

MMS approval is required to install, 

maintain, and operate all new pipelines 

on the OCS. This category covers the 

responsibilities of the applicant and 

MMS in the pipeline application 

process. The conditions under which 

the Secretary of the Interior may cancel 

approval of a pipeline application are 

also addressed. 

The proposed rule covers: 

• When the Regional Supervisor (RS) 

may require additional information; 

• When the RS may limit the 

information needed; 

• When an application may be 

withdrawn; 

• Requirements for informing 

impacted lessees, lease operators, and 

pipeline ROW holders; and 

• Information submitted to affected 

States. 

MMS added a section to allow the RS 

to require additional information for 

those situations where conditions or 

features may warrant further scrutiny. 

Additionally, MMS added a section to 

allow the RS to limit the information to 

be submitted, if that information was 

submitted previously or is otherwise 

available. MMS is also codifying the 

Coastal Zone Management information 

requirements for affected States for the 

first time in the pipeline regulations. 

Guidance on this subject is currently 

contained in an NTL which would be 

eliminated by this proposed rule. 

The proposed rule documents the 

current process that MMS follows in its 

standard review of applications. That 

process is not addressed in the current 

regulations. Steps in the process 

include: 

• Initial review 

• Compliance review 

• Environmental impact evaluation 

• Amendments 

• Approval restrictions 

• Objections to coastal zone consistency 

certifications 

Pipeline Application Contents 

The information that the applicant 

must supply to MMS in a pipeline 

application is spelled out, in detail, in 

this category. The proposed rule 

consolidates current MMS application 

content and application process 

requirements, with related guidance 

from several NTLs and one LTL. 

Activities for lease term pipelines 

must be covered in DOCDs in the 

western Gulf of Mexico (GOM), and in 

DPPs in the eastern GOM and in the 

Pacific and Alaska OCS Regions. The 

requirements for these OCS plans are 

covered in 30 CFR 250, subpart B, Plans 

and Information. The proposed rule 

imposes similar requirements for 

information on ROW pipeline 

applications that must be addressed in 

the DOCD and DPP required by subpart 

B for lease term pipelines. Current 

pipeline ROW regulations do not 

impose these requirements. They are 

contained as guidance in an NTL. As 

stated earlier, this proposed rulemaking 

would eliminate four NTLs and one 

LTL. 

Proposed § 250.1016 lists other 

agencies and entities with which an 

applicant must coordinate, and the 

information required by MMS 

documenting that the coordination has 

taken place. Proposed §§ 250.1017 and 

1018 provide a detailed description of 

the information required regarding the 

location of the proposed pipeline. In 

addition, proposed §§ 250.1019 and 

1020 provide a detailed description of 

the information required in the 

application regarding horizontal 

components, risers, appurtenances, and 

schematic flow diagrams. 

Applicants currently provide much of 

the information required in proposed 

§§ 250.1022, 1023, and 1025 regarding 

construction, support, and products 

under the guidance of the NTLs listed 

earlier. The information requirements in 

proposed § 250.1026 regarding 


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56444 Federal Register / Vol. 72, No. 191 / Wednesday, October 3, 2007 / Proposed Rules 

biological and archaeological resources 

are also currently submitted under the 

guidance of the NTLs. The proposed 

rule codifies current procedures. 

The requirements in proposed 

§ 250.1028 regarding oil spill response 

plans, and those in proposed § 250.1029 

regarding oil spill financial 

responsibility for ROW pipelines, are 

both new to subpart J. However, the 

proposed regulations simply reference 

current requirements in 30 CFR parts 

254 and 253, respectively. 

The information requirements in 

proposed § 250.1030 regarding 

environmental impact analyses for ROW 

pipelines are new to the pipeline 

regulations, but are necessary for MMS 

to comply with NEPA. 

Pipeline Design 

Section 250.1002 of the current 

regulations contains pipeline design 

requirements. The proposed rule 

expands the design requirements into 

§§ 250.1031 through 250.1036. The 

proposed rule includes performance 

requirements for designing a pipeline to 

mitigate and withstand the detrimental 

effects of environmental factors such as 

currents, storm and ice scouring, mud 

slides, earthquakes, hurricanes, and 

load factors such as differential 

pressures, dynamic loads, expansion 

and contraction, corrosion, and 

hydrogen sulfide gas. 

The proposed rule includes the 

formula for internal design pressure for 

steel horizontal components and risers 

that is in the current regulations. 

However, the proposed rule allows the 

use of equations from sections 4.3.1, 

4.3.1.1, or 4.3.1.2 of API Recommended 

Practice 1111, Design, Construction, 

Operation, and Maintenance of Offshore 

Hydrocarbon Pipelines (Limit State 

Design) (API RP 1111), in lieu of the 

current formula. This may result in a 

cost savings to the pipeline company 

depending on the type of pipe required 

by the different equations. It gives the 

pipeline company a choice in designing 

the pipeline. In addition, the proposed 

rule incorporates the formulas in 

sections 4.3.2.1 and 4.3.2.2 of API RP 

1111 for predicting the external design 

(collapse) pressure for steel pipe, and 

the formulas in sections 4.5.4 and 

4.1.6.2 of API RP 1111 for designing a 

catenary riser for a fixed structure. The 

proposed rule would incorporate these 

seven sections of API RP 1111 into the 

regulations. 

Pipeline Fabrication 

MMS included new performance 

requirements for pipeline fabrication in 

the proposed rule. The requirements are 

general in nature, and cover quality 

control, design tolerances, recognized 

engineering practices, and compliance. 

Pipeline Construction 

Many of the proposed requirements in 

this category are new to the regulations. 

These include the performance 

requirements in the proposed 

§ 250.1040, and the requirements for 

constructing a pipeline in or near a 

designated use area, and in or near a 

sensitive biological feature or 

archaeological resource. Also new in the 

proposed regulations are requirements 

for hazard mitigation and installing hot 

taps. 

MMS included in this proposed rule 

a requirement to notify the military 

when crossing established military 

warning and water test areas, and a 

recommendation to notify the U.S. Coast 

Guard (USCG) for the preparation of a 

Notice to Mariners. 

The proposed rule would require 

pipeline companies in the Alaska OCS 

Region (AKOCSR) and Pacific OCS 

Region (POCSR) to take cathodic 

protection readings on all pipelines 

during repairs and hot tap installations, 

not just on those pipelines that are over 

20 years old. MMS added this 

requirement to ensure that the entire 

length of the pipeline remains protected 

from external corrosion. MMS also 

proposes requirements for protecting the 

coating on the horizontal component of 

the pipeline and the riser during 

construction, and we changed the 

requirements for protecting 

appurtenances and crossings so that all 

equipment must have protection or 

cover in water depths less than 500 feet. 

The separation for pipeline crossings is 

changed from 18 inches to 12 inches. 

The reduction still provides adequate 

protection, and is compatible with 

industry standards and DOT 

requirements. However, MMS invites 

your specific comments on this 

proposed change. 

The U.S. Department of Defense 

(DOD) provided the requirements in 

proposed § 250.1047(a) regarding 

military test and water test areas. They 

are currently part of the lease agreement 

and stipulations. The requirements in 

proposed § 250.1048 regarding sensitive 

biological features and archaeological 

resources are taken from guidance 

contained in several of the previously 

listed NTLs. Pipeline companies have 

followed the guidance in these NTLs 

and their predecessors for several years. 

The proposed rule would require 

companies to submit construction 

reports within 45 days after completion 

of pipeline construction, instead of the 

current 90 days. This is a reasonable 

requirement with today’s technology, 

and will allow for faster updating of 

maps. 

Pipeline Risers Connected to Floating 

Platforms 

The proposed rule establishes a 

Pipeline Riser Verification Program for 

risers connected to floating platforms. 

The proposed rule at § 250.1052 

requires that all such pipeline risers be 

subject to separate verification that 

necessitates the use of a Certified 

Verification Agent (CVA) specifically for 

the pipeline riser. This requirement 

would be in addition to the platform 

verification requirements in subpart I. 

MMS is proposing this requirement 

because pipeline risers from floating 

platforms are highly sophisticated and 

complicated components that require 

extensive specialized technical analysis 

and oversight. Also, riser failures could 

have high failure consequences, such as 

spills, explosions, fires and other major 

incidents. The proposed rulemaking 

would eliminate one NTL on this 

subject. 

Pipeline Pressure Testing 

This category covers hydrostatic 

pressure testing and leak testing. The 

proposed rule provides a definition of a 

successful hydrostatic pressure test, 

including when to conduct these tests 

and how to report the results. Most of 

the proposed requirements are the same 

as the current regulations. However, 

there are some new requirements for 

pressure testing after a repair using a 

spool piece. 

The requirements for submitting test 

results are revised to include specific 

information in the report. The proposed 

rule lists the instances when a 

hydrostatic pressure test is required, 

and the pressure requirements for the 

test. MMS is also proposing specific 

requirements for leak tests. In addition, 

the proposed rule allows pretesting of a 

spool piece for a repair to conform to 

DOT regulations. 

Pipeline Safety Equipment 

This category covers the required 

safety equipment for pipelines. This 

includes departing, incoming, crossing, 

and bi-directional pipelines and 

pipeline pumps. The proposed rule 

describes the types, location, and 

operation of the required equipment. It 

also addresses requirements for 

providing redundant safety devices and 

for dealing with safety equipment 

failure. 

This category begins with a general 

performance requirement. MMS 

proposes to expand the regulatory 

requirements for departing pipelines to 

include certain requirements currently 


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Federal Register / Vol. 72, No. 191 / Wednesday, October 3, 2007 / Proposed Rules 56445 

imposed as conditions of approval for 

various permits. These requirements 

include the settings of high/low 

pressure sensors (PSHLs), and methods 

to determine the settings. In addition, 

the RS may require the installation of a 

flow safety valve (FSV) or a shutdown 

valve (SDV) on departing pipelines. 

These requirements are currently 

common industry safety practices. 

On new incoming, crossing, and 

bidirectional pipelines, the proposed 

rule requires that companies install 

SDVs no more than 10 feet from the 

boarding pipeline riser and in an 

unclassified area. On new crossing 

pipelines, the proposed rule requires 

installation of an FSV on unmanned and 

non-production platforms to prevent 

backflow. MMS currently imposes these 

requirements as conditions of approval 

to prevent spills and decrease the 

likelihood of explosions and fires. 

If the safety equipment fails, the 

proposed rule requires that the company 

shut in all pipelines immediately to 

ensure safety and protect the 

environment. Pipeline companies may 

not resume operations until the 

equipment is repaired or replaced, 

unless an equivalent degree of 

protection is provided. 

Pipeline Leak Detection 

The proposed rule allows the RS to 

require leak detection systems if MMS 

determines that they are necessary. The 

proposed rule recommends the use of 

current technology. This includes, but is 

not limited to, computational pipeline 

monitoring (CPM), including 

supervisory control and data acquisition 

(SCADA) systems. 

Pipeline Internal Corrosion Control and 

Flow Assurance 

This category includes new 

requirements to prevent internal 

pipeline corrosion and to maintain 

adequate flow over the life of a pipeline. 

These proposed changes are based on 

current industry practices included in 

API RP 1111. 

Pipeline Operations and Maintenance 

Proposed § 250.1079 would require 

the preparation of an operations and 

maintenance manual, an integrity 

management program, an emergency 

plan, and a personnel qualification 

program. MMS is proposing these 

requirements to ensure that lessees, 

designated lease operators, and pipeline 

ROW holders maintain OCS pipelines in 

accordance with current industry 

practices, and that the personnel 

performing the maintenance are capable 

of that task. Recent pipeline leaks in 

onshore pipelines in the United States, 

and other integrity issues associated 

with those pipelines, have prompted 

MMS to address offshore pipeline 

integrity in this proposed rule. The new 

requirements in § 250.1079 are 

performance based. At a later time, 

MMS may propose more prescriptive 

regulations if research indicates the 

need for them. 

Proposed § 250.1080 would require 

marking pipeline segment numbers on 

the pipeline at each platform. The 

proposed rule would require marking 

immediately for new pipelines, but 

allows 6 months to mark existing 

pipelines. The proposed rule allows for 

the use of the component identifier from 

API RP 14C, Recommended Practice for 

Analysis, Design, Installation, and 

Testing of Basic Surface Safety Systems 

for Offshore Production Platforms 

(incorporated by reference into the 

regulations at § 250.198) using the 

MMS-assigned pipeline segment 

number as the unique identifier. In API 

RP 14C, pipelines are identified by the 

codes KAA (bi-directional), KAH 

(departing), and KAQ (incoming). Under 

the proposed rule, the MMS-assigned 

pipeline segment number could be 

added to the API code (e.g., KAH–1425, 

where 1425 is the MMS-assigned 

pipeline segment number). 

MMS included new requirements for 

the preparation of an H2S Contingency 

Plan for pipelines that transport 

products containing H2S in certain 

concentrations. Since such plans are 

required for all other OCS operations 

where H2S is present, this proposed 

requirement makes the pipeline 

regulations consistent with the rest of 

our regulations. 

Although the requirements in 

proposed § 250.1083 regarding remote 

operations are also new to the 

regulations, they are based on guidance 

from a current NTL covering operations 

during storms or other emergencies 

requiring evacuation. 

The specific requirements in 

proposed § 250.1084 covering testing of 

safety equipment are new to the 

pipeline regulations. The current 

regulation at § 250.1004(a) is a 

performance based requirement for 

testing safety equipment. The proposed 

rule would require testing as outlined in 

API RP 14C. Pipeline safety equipment 

is currently tested in accordance with 

the requirements in subpart H, Oil and 

Gas Production Safety Systems. This 

revision places the requirements in 

subpart J. Prudent companies already 

follow these procedures in testing 

pipeline safety equipment. 

The proposed rule includes 

notification and reporting requirements 

for safety equipment and pipelines 

removed from service. In addition, MMS 

proposes testing requirements for 

resuming operations on pipelines that 

have been shut in. Proposed § 250.1088 

would require suspension of pipeline 

operations and notification to MMS if a 

pipeline leaks. The notification 

requirement is based on guidance in a 

current LTL (which would be 

eliminated by this proposed rule), and 

is also normally a condition of approval 

to reactivate a pipeline. We included the 

requirements in proposed § 250.1089, 

covering flaring gas from a pipeline, to 

be consistent with the regulations in 

subpart K, Oil and Gas Production 

Rates. 

Pipeline Modifications and Repairs 

MMS has completely revised the 

regulations covering pipeline 

modifications and pipeline repairs to 

more closely resemble the requirements 

covering new pipelines. The 

information required in a modification 

application is expanded to satisfy safety 

and environmental protection 

requirements. MMS incorporated 

guidance currently addressed in an NTL 

to satisfy Coastal Zone Management Act 

(CZMA) requirements if the 

modification affects any States. For 

those modifications that involve the 

installation of a hot tap, we proposed 

requirements covering the design, 

location, and description of the hot tap. 

In addition, the proposed rule would 

require the submission of a modification 

report within 30 days of completion. 

The new information proposed for a 

repair application is necessary for safety 

and the protection of the environment. 

The proposed rule would require that 

the company submit a repair report 

within 30 days of the completion of the 

repair. The report must include location 

information, confirmation of the 

damage, confirmation that the repair 

was completed as approved, the results 

of pressure tests, and the cathodic 

protection measurements. 

MMS revised the requirements 

(proposed § 250.1096) for repairing a 

pipeline with a clamp to differentiate 

those repairs below the splash zone 

from those in or above the splash zone. 

If you use a clamp to repair the pipeline 

on the horizontal component or on the 

pipeline riser below the splash zone, the 

proposed rule allows for the use of a 

welded clamp or a mechanical clamp. 

The proposed rule would require an 

application for a permanent repair in or 

above the splash zone, if you 

temporarily repaired the pipeline with a 

mechanical clamp. The permanent 

repair would require the use of a welded 

clamp, a spool piece, or other method 

approved by the RS. 


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56446 Federal Register / Vol. 72, No. 191 / Wednesday, October 3, 2007 / Proposed Rules 

Pipeline Surveying, Monitoring, and 

Inspection 

The proposed rule would require 

visual surveys of all pipeline routes at 

least monthly, and gives several 

methods for conducting the surveys. In 

addition, the proposed rule would 

require annual inspections of each 

pipeline riser in and above the splash 

zone, and inspection of the underwater 

portions of the riser in conjunction with 

the platform inspection requirements in 

30 CFR 250, subpart I, Platforms and 

Structures. MMS included proposed 

requirements, currently in effect as 

guidance in an NTL, for inspecting the 

pipeline after a storm or earthquake. 

These proposed requirements are 

considered critical to the safe operation 

of pipelines. 

MMS proposes to change the deadline 

for reporting anode system inspections 

from March 1 to October 31 of each 

year, with the inspections to be 

conducted no later than September 30 of 

each year. This synchronizes MMS 

requirements for these reports with the 

timing of industry, since the inspections 

are normally conducted during the 

summer months. Pipeline companies 

currently either submit reports for 

inspections that they performed the 

previous summer, which are almost a 

year old, or they conduct the 

inspections when the weather is not 

ideal. By changing the reporting 

deadline to October 31 of each year, 

MMS ensures that the companies 

submit current information. The 

proposed regulation also allows the 

company to conduct tests at anytime 

and submit the reports within 60 days 

of the test, but no later than October 31 

of each year. This provides more 

flexibility to the company in the timing 

of the tests. 

The ultrasonic test inspections, inline inspections, and trawling tests in 

proposed § 250.1103(d), (e), and (f) are 

new to the regulations. The RS may 

require these inspections and tests if 

specific conditions indicate the need for 

them. 

Pipeline Decommissioning 

The regulations for decommissioning 

a pipeline are mostly unchanged. MMS 

is proposing to relocate the pipeline 

decommissioning regulations from 30 

CFR 250, subpart Q, Decommissioning 

Activities, to subpart J since these 

regulations are unique to pipeline 

operations. This would consolidate 

almost all pipeline specific regulations 

in one subpart. MMS requests your 

specific comments on this proposal, and 

comments on whether we should adopt 

this approach with other subparts 

within 30 CFR 250. 

MMS added one section (proposed 

§ 250.1113) covering the requirements 

for re-commissioning a decommissioned 

pipeline. This section refers the 

applicant to the pipeline application 

process in proposed § 250.1007. 

Pipeline Right-of-Way (ROW) Grants 

This category covers the terms and 

conditions for holding a pipeline ROW 

grant, including when a grant is needed, 

who may hold a grant, and how to apply 

for a grant. It also covers: 

• Bonding 

• Application submittal 

• MMS review 

• Compliance 

• Environmental review 

• State consistency review 

• Modification 

• Cessation of operations 

• Assigning a grant 

• Suspensions 

• Relinquishing a grant 

• Terminating a grant 

Because of certain administrative 

similarities between pipeline ROW 

grants and OCS leases, many of the 

proposed changes are based on or 

derived from the regulations in 30 CFR 

256, which address OCS leasing. Each 

separate ROW pipeline requires a 

separate ROW grant. The proposed 

financial security requirements are more 

detailed than in the current regulations. 

Currently, pipeline companies must 

furnish an area bond in the amount of 

$300,000 to hold pipeline ROW grants 

in an MMS OCS Region. The proposed 

rule would allow a pipeline ROW 

holder the option of choosing to cover 

the pipeline ROW with either a 

$300,000 pipeline ROW grant 

individual bond or a $1,000,000 

pipeline ROW grant area bond. The 

$1,000,000 area bond will cover all 

pipeline ROW grants held by a company 

in one MMS OCS Region. These 

requirements represent an increase from 

the current bonding amount, and will 

more accurately reflect the actual 

liabilities in decommissioning 

pipelines. The new proposed amounts 

would apply to all existing and future 

grants. Companies would be required to 

cover existing pipeline ROW grants by 

these increased amounts within 6 

months after the rule becomes effective. 

The Regional Director may also require 

additional security based on an 

evaluation of a company’s ability to 

carry out present and future financial 

obligations under the pipeline ROW 

grant. Companies have the opportunity 

to provide MMS with written or oral 

arguments during the evaluation. These 

securities are required primarily to 

ensure that the U.S. Government has 

sufficient funds available to properly 

decommission a pipeline in the event 

that the pipeline company is unable or 

unwilling to do so. The proposed rule 

includes language giving MMS the 

ability to reduce the amount required by 

a bond, to deal with lapses in bonds, 

and to determine bond forfeiture. 

The service fee for a pipeline ROW 

grant would remain unchanged. The 

proposed rule addresses pipeline ROW 

grant assignments. The conditions for 

when MMS will suspend a ROW grant 

are spelled out more clearly. 

The MMS is proposing to increase the 

annual rental fees for pipeline ROW 

grants to reflect the current rates 

established for new rights-of-use and 

easement (see 30 CFR 250.160(f) and (g)) 

and pipeline accessory structures (see 

30 CFR 250.1012(b)). The amount 

established by these regulations are 

$5.00 per acre per year for sites in water 

depths less than 200 meters and $7.50 

per acre per year for sites in water 

depths 200 meters or greater. The 

current rental rate for pipeline ROW 

grants is $15 per mile. A pipeline ROW 

grant is 200 feet wide. Therefore, the 

area of a pipeline ROW grant is 24.24 

acres per mile. At $5.00 per acre, the 

rental rate would be approximately $125 

per mile (actually $121.20). Since 

raising the rental for pipeline ROW 

grants to $125 per mile from $15 per 

mile is a major increase, MMS is 

proposing to raise the rental in two 

steps. This proposed rule would 

increase the annual rental for pipeline 

ROW grants to $70 per mile. MMS will 

propose the second increase to $125 per 

mile in a future rulemaking. Although 

this is a large increase, MMS believes 

the higher fee is a fair and reasonable 

amount to pay for access to Federal 

lands. 

The terms and conditions for holding 

a pipeline ROW grant remain 

unchanged with respect to the OCS 

Lands Act provisions requiring ROW 

pipelines to transport oil and natural gas 

produced in the vicinity of the pipeline 

without discrimination, and to provide 

open access. 

The proposed rule (§ 250.1131(j)) 

would make compliance with Executive 

Order 11246, regarding nondiscrimination in employment, a 

condition for holding a pipeline ROW 

grant. Therefore, the requirement 

(currently § 250.1015(d)) for pipeline 

ROW grant applicants to include the 

‘‘Non-discrimination in Employment’’

form (YN 3341–1) with their 

applications is eliminated. 

This category also covers 

relinquishing a pipeline ROW grant. It 


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addresses the application requirements, 

rental payments, delinquent payments, 

the effective date of relinquishment, and 

financial securities. Proposed 

§ 250.1137 covers cancellation, 

forfeiture, and expiration of pipeline 

ROW grants. One of the grounds for 

forfeiture in this proposed rule 

(§ 250.1137(b)(2)) concerns open and 

nondiscriminatory access to shippers. 

The MMS recently published in the 

Federal Register a proposed rule (72 FR 

17047, April 6, 2007) which would 

establish 30 CFR part 291, Open and 

Nondiscriminatory Movement of Oil 

and Gas as Required by the Outer 

Continental Shelf Lands Act. Part 291 

will be referenced in this regulation 

when it (part 291) becomes final. 

The proposed rule covers the 

obligations of the pipeline ROW holder 

after a pipeline ROW grant is terminated 

for any reason. The pipeline ROW 

holder has 1 year after the grant 

terminates to decommission the 

associated ROW pipeline. Current 

regulations require that the company 

remove the pipeline. However, the 

proposed rule allows for ROW pipelines 

to be decommissioned in place if the RS 

approves. The proposed rule also 

provides requirements for recommissioning of decommissioned 

pipelines. 

Accessories to Right-of-Way (ROW) 

Pipelines 

The proposed rule expands the 

current subpart J regulations for 

accessories to ROW pipelines. However, 

there are very few new requirements. 

The proposed rule clarifies that 

accessories to ROW pipelines are 

subject to the requirements currently 

contained in 30 CFR 250, subpart H, Oil 

and Gas Production Safety Systems, and 

30 CFR 250, subpart I, Platforms and 

Structures, just like all other OCS 

structures. It also clarifies that 

applications for new accessories are 

subject to Coastal Zone Management Act 

consistency requirements. The proposed 

rule documents the internal MMS 

process for approving an accessory 

application. 

Appendix 

The following appendix will not 

appear in the Code of Federal 

Regulations. Appendix A is included in 

this proposed rule so we may solicit 

your comments on a proposed new form 

for use in reporting some of the 

information required in subpart J. 

Appendix A—Department of the 

Interior—Form MMS 153, ‘‘Notification 

of Pipeline Installation/Relocation/ 

Hydrotest’’ 

BILLING CODE 4310–MR–P 


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Procedural Matters 

Public Availability of Comments 

Before including your address, phone 

number, email address, or other 

personal identifying information in your 

comment, you should be aware that 

your entire comment—including your 

personal identifying information—may 

be made publicly available at any time. 

While you can ask us in your comment 

to withhold your personal identifying 

information from public review, we 

cannot guarantee that we will be able to 

do so. 

Regulatory Planning and Review 

(Executive Order (E.O.) 12866) 

This proposed rule is not a significant 

rule as determined by the Office of 

Management and Budget (OMB), and is 

not subject to review under E.O. 12866. 

(1) The proposed rule would not have 

an annual effect of $100 million or more 

on the economy. It would not adversely 

affect in a material way the economy, 

productivity, competition, jobs, the 

environment, public health or safety, or 

State, local, or tribal governments or 

communities. There will be an increase 

in administrative costs, mainly 

information submitted to MMS in 

applications, plans, requests, and 

reports. MMS estimates that this 

proposed rule would cost the industry 

approximately $11.8 million in 

administrative costs each year. For more 

detail about these costs, please see the 

Paperwork Reduction Act section in this 

preamble. We estimate that the current 

pipeline regulations cost the industry 

approximately $7 million in 

administrative costs each year. 

Therefore, this proposed rule increases 

the annual administrative cost to 

industry by $4.8 million. However, the 

industry is currently submitting most of 

the information which would be 

required by this proposed rule as a 

condition of approval for a pipeline or 

pipeline right-of-way, or as requested in 

the NTLs mentioned earlier in this 

preamble. In addition, we estimate that 

this proposed rule will add $10.2 

million in one-time costs to industry to 

comply with the new requirements for 

pipeline integrity management plans 

and associated manuals. The increased 

rental rate for pipeline ROW grants 

would result in an additional annual 

cost of $1.2 million to the industry. See 

the Regulatory Flexibility Act section of 

this preamble for more information. The 

MMS estimates that increasing the areawide pipeline ROW bond from $300,000 

to $1,000,000 would result in an 

additional annual cost of $3.7 million to 

the industry. This estimate is based on 

300 area-wide pipeline ROW bonds in 

the GOM. The increased amount per 

bond would be $700,000. The average 

annual cost per bond in the GOM is 1.75 

percent of the bond amount. The 

average annual increase in pipeline 

ROW bonding costs would be: 300 × 

$700,000 × 1.75% = $3,675,000. In 

summary, there would be an annual 

increase in costs to the industry of 

approximately $9.7 million plus a one 

time cost of $10.2 million. The overall 

impact would be less than $100 million. 

Most of the changes in the proposed 

rule clarify existing requirements or 

incorporate standard practices. Most 

operations would continue without 

many changes. This proposed rule is 

designed to codify existing practices 

that MMS and industry have generally 

followed for many years. 

(2) The proposed rule would not 

create a serious inconsistency or 

otherwise interfere with an action taken 

or planned by another agency. 

Both DOI and DOT have jurisdiction 

over OCS oil and natural gas pipelines. 

These jurisdictional boundaries are 

defined in the proposed rule. 

The DOI and DOT have a MOU dated 

December 10, 1996. According to the 

MOU, producer-operated pipelines are 

generally under DOI jurisdiction and 

transporter-operated pipelines are 

generally under DOT jurisdiction. The 

MOU includes the flexibility to cover 

situations that do not correspond to the 

general definition of the jurisdictional 

boundary as ‘‘the point at which 

operating responsibility transfers from a 

producing operator to a transporting 

operator.’’ The DOI and DOT may, 

through their enforcement agencies and 

in consultation with the affected parties, 

agree to exceptions to this MOU on a 

facility-by-facility or area-by-area basis. 

Companies may also petition DOI and 

DOT for exceptions to this MOU. 

(3) The proposed rule would not alter 

the budgetary effects of entitlements, 

grants, user fees, or loan programs, or 

the rights or obligations of their 

recipients. The proposed rule does not 

address entitlements, grants, user fees, 

or loan programs; and therefore, can 

have no effects on such programs. The 

proposed rule does increase the rental 

fees paid for pipeline ROW grants by the 

pipeline companies. 

(4) The proposed rule would not raise 

novel legal or policy issues. Most of the 

requirements in the proposed rule 

represent established MMS and industry 

practices, and are in accordance with 

the provisions of the DOT/DOI MOU 

dated December 10, 1996. 

Regulatory Flexibility Act (RFA) 

The Department certifies that this 

proposed rule would not have a 

significant economic effect on a 

substantial number of small entities 

under the RFA (5 U.S.C. 601 et seq.). A 

regulatory flexibility analysis is not 

required. 

This proposed rule applies to all 

lessees, designated lease operators, and 

pipeline ROW holders operating on the 

OCS. Lessees/operators are classified 

under the Small Business 

Administration’s North American 

Industry Classification System (NAICS) 

code 211111, Crude Petroleum and 

Natural Gas Extraction. Under this 

NAICS code, companies with fewer than 

500 employees are considered small 

businesses. MMS estimates that 130 

lessees/operators explore for and 

produce oil and gas on the OCS. 

Approximately 70 percent of them (91 

companies) fall into the small business 

category. 

A pipeline ROW holder (nonproducer) is a small entity if it is a 

liquid pipeline company with fewer 

than 1,500 employees, or a natural gas 

pipeline company with gross annual 

receipts of $25 million or less. MMS’s 

database indicates that there are 88 

pipeline ROW holders who do not own 

an interest in any oil and gas leases on 

the OCS. Fifty-seven of these companies 

are either major energy companies (large 

oil and gas or pipeline transmission 

companies), or wholly owned 

subsidiaries of such companies. Another 

13 entities were either formed by 

partnerships among major producers 

and transporters, or have ‘‘arms-length’’

contractual relationships with several 

major producers on the OCS for which 

they provide transportation services. It 

is our understanding that in such 

relationships, one of the major partners 

usually serves as the ‘‘managing 

partner’’ of the entity so that the entity 

(whether a partnership or a corporation) 

is not actually independent in the usual 

sense. The remaining 18 entities could 

be categorized as small independent 

pipeline companies in the sense that 

they provide transportation services for 

several non-major oil or gas producers. 

These companies are classified by 

NAICS code 213112, Support Activities 

for Oil and Gas Operations. Thus, there 

are 218 companies affected by this 

proposed rule, of which 109 would be 

considered small businesses. 

The costs of installing, operating, and 

maintaining pipelines on the OCS are 

high due to the operating environment, 

i.e., marine environment, water depth, 

distance from shore. The costs imposed 

by this proposed rule are mainly due to 

recordkeeping and reporting, and are 

therefore minor in comparison to the 

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The increase in annual rental fees for 

pipeline ROW grants appears to be 

substantial, going from $15 per mile to 

$70 per mile. The MMS initially 

intended on raising the rental to the 

same rate as paid by holders of rightsof-use and easement and operators of 

accessory structures on the OCS ($5.00 

per acre per year). Increasing the rental 

to $5.00 per acre would result in an 

annual rental rate of approximately 

$125 per mile. This proposed rule 

would increase the annual rental for 

pipeline ROW grants to $70 per mile (1⁄2

of the increase). MMS will propose the 

second increase in a future rulemaking. 

This acreage is computed based on a 

pipeline ROW being 200 feet wide. 

Therefore, the area of a pipeline ROW 

grant is 24.24 acres per mile. At $5.00 

per acre, the rental rate would be 

approximately $125 per mile (actually 

$121.20). The MMS estimates that there 

are currently 20,114 miles of active 

ROW pipelines in the Gulf of Mexico 

comprised of 2,512 pipeline segments. 

Since MMS collects rentals on fractions 

of a mile for each segment, we added a 

correction factor to more accurately 

represent the mileage for which pipeline 

ROW holders are charged for annual 

rentals. Assuming the average fraction is 

0.5 mile, the additional mileage will be 

the number of segments times 0.5. 

Therefore, the total mileage for which 

MMS collects rental is 20,114 + 1,256 = 

21,370. At $15 per mile, the total annual 

rental comes to $320,550. At $70 per 

mile, the total annual rental amounts to 

$1,495,900. However, this 

approximately $1.2 million annual 

increase is spread over the total number 

of pipeline ROW holders, and it is a 

minor cost when compared to the costs 

of installing, operating, and maintaining 

ROW pipelines. 

Your comments are important. The 

Small Business and Agriculture 

Regulatory Enforcement Ombudsman 

and 10 Regional Fairness Boards were 

established to receive comments from 

small business about Federal agency 

enforcement actions. The Ombudsman 

will annually evaluate the enforcement 

activities and rate each agency’s 

responsiveness to small business. If you 

wish to comment on the actions of 

MMS, call 1–888–734–3247. You may 

comment to the Small Business 

Administration without fear of 

retaliation. Disciplinary action for 

retaliation by an MMS employee may 

include suspension or termination from 

employment with the DOI. 

Small Business Regulatory Enforcement 

Fairness Act (SBREFA) 

This proposed rule is not a major rule 

under the SBREFA (5 U.S.C. 804(2)). 

This proposed rule: 

a. Would not have an annual effect on 

the economy of $100 million or more. 

The proposed rule deals with OCS 

pipeline operations. It would ensure 

that safe and environmentally sound 

pipeline operations continue. The 

impacts of this proposed rule would not 

be economic. This proposed rule would 

not have a large impact on the costs of 

OCS pipeline operations, and would not 

have an impact on oil or natural gas 

prices. Oil and natural gas prices are 

driven more by market factors than by 

the cost of production. 

b. Would not cause a major increase 

in costs or prices for consumers, 

individual industries, Federal, State, or 

local government agencies, or 

geographic regions. This proposed rule 

would not significantly increase the cost 

of pipeline operations on the OCS since 

most of the requirements are established 

practices that industry has followed for 

years. In general, doing business on the 

OCS (of any kind) is expensive. Any 

new costs imposed by this proposed 

rule would be minor. 

The proposed rule would not have a 

large impact on the costs of OCS 

pipeline operations, and will not have 

an impact on oil or natural gas prices. 

Oil and natural gas prices are driven 

more by market factors than by the cost 

of production. 

c. Would not have significant adverse 

effects on competition, employment, 

investment, productivity, innovation, or 

the ability of U.S.-based enterprises to 

compete with foreign-based enterprises. 

Leasing on the OCS is limited to 

residents of the U.S. or companies 

incorporated in the U.S. This proposed 

rule would not change that requirement. 

The proposed rule would not interfere 

with competition and would not impact 

employment, investment, or 

productivity. The proposed rule 

encourages innovation since it allows 

for alternative methods of conducting 

pipeline operations. 

Unfunded Mandate Reform Act (UMRA) 

This proposed rule would not impose 

an unfunded mandate on State, local, or 

tribal governments or the private sector 

of more than $100 million per year. The 

proposed rule would not have a 

significant or unique effect on State, 

local or tribal governments, or the 

private sector. A statement containing 

the information required by the UMRA 

(2 U.S.C. 1531 et seq.) is not required. 

There are no mandates for State, local, 

or tribal governments. This proposed 

rule only impacts pipeline companies 

on the OCS; it does not affect State or 

local governments or tribal lands. 

Takings Implication Assessment 

(Executive Order 12630) 

The proposed rule is not a 

governmental action capable of 

interference with constitutionally 

protected property rights. Thus, MMS 

did not need to prepare a Takings 

Implication Assessment according to 

E.O. 12630, Governmental Actions and 

Interference with Constitutionally 

Protected Property Rights. The proposed 

rule revises existing pipeline 

regulations. It would not prevent any 

lessee, designated lease operator, or 

pipeline ROW holder from performing 

operations on the OCS, as long as they 

complied with the regulations. 

Federalism (Executive Order 13132) 

With respect to E.O. 13132, this 

proposed rule would not have 

federalism implications. This proposed 

rule would not substantially and 

directly affect the relationship between 

the Federal and State governments. To 

the extent that State and local 

governments have a role in OCS 

activities, this proposed rule would not 

affect that role. 

The OCS is under Federal jurisdiction 

seaward from the State’s jurisdiction. 

There is no overlap between State and 

Federal jurisdiction. This proposed rule 

applies only to areas under Federal 

jurisdiction. None of the changes in this 

proposed rule would affect areas that 

are controlled by the States. It would 

not change the way that the States and 

the Federal government interact, or the 

way that States interact with private 

companies. 

Civil Justice Reform (Executive Order 

12988) 

With respect to E.O. 12988, the Office 

of the Solicitor has determined that the 

proposed rule does not unduly burden 

the judicial system and meets the 

requirements of sections 3(a) and 3(b)(2) 

of the Order. 

Paperwork Reduction Act (PRA) 

This proposed rule contains a 

collection of information that will be 

submitted to the Office of Management 

and Budget (OMB) for review and 

approval under § 3507(d) of the PRA. 

The title of the collection of information 

for this rule is 30 CFR 250, Subpart J 

Pipelines and Pipeline Rights-of-Way 

(Proposed Rulemaking) (OMB Control 

Number 1010–0050, expiration 3/31/ 

09). Respondents primarily are an 

estimated 130 Federal OCS lessees and 


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designated lease operators and 88 

pipeline ROW holders. Other potential 

respondents are companies that submit 

letters of no objection to, or comments 

on, pipeline applications; certified 

verification agents (CVAs), independent 

certification agents (IVAs), or other 

third-party reviewers; and surety or 

other third-party guarantors. The 

frequency of response varies depending 

upon the requirement. Responses to this 

collection of information are mandatory 

or required to obtain or retain a benefit. 

MMS will protect proprietary 

information according to the Freedom of 

Information Act and 30 CFR 250.197, 

‘‘Data and information to be made 

available to the public or for limited 

inspection.’’

As discussed earlier in the preamble, 

the proposed rule is a complete revision 

of the current pipelines and pipeline 

rights-of-way regulations at 30 CFR 250, 

subpart J. It incorporates guidance from 

several NTLs and one LTL that 

respondents currently follow, and 

would codify various conditions that 

MMS imposes when approving pipeline 

applications to ensure that pipelines are 

installed and operated in a safe and 

environmentally sound manner. The 

OMB approved the information 

collection burden of the current 30 CFR 

250, subpart J regulations under control 

number 1010–0050 (107,874 burden 

hours; and $2,369,400 non-hour burden 

cost service fees). When the final 

revised subpart J regulations take effect, 

the information collection burden 

approved for this rulemaking will 

replace the collection under 1010–0050 

in its entirety. 

A table at § 250.198 lists all of the 30 

CFR 250 incorporated documents. That 

table would be revised to include the 

new 30 CFR 250, subpart J, incorporated 

documents added or updated under this 

proposed regulation. There are also 

several proposed changes to 30 CFR 

parts 253 and 254. However, these 

proposed changes do not affect the 

currently approved information 

collection burden of 30 CFR 250, 

subpart A (OMB Control Number 1010–

0114) or 30 CFR parts 253 and 254 

(OMB Control Numbers 1010–0106 and 

1010–0091, respectively). 

The current regulations on pipeline 

decommissioning and associated 

information collection are located in 30 

CFR 250, subpart Q. The rule proposes 

to relocate the pipeline 

decommissioning requirements into the 

revised 30 CFR 250, subpart J 

regulations. The OMB approved the 

information collection burden of the 

current subpart Q regulations under 

control number 1010–0142. When the 

new 30 CFR 250, subpart J final 

regulations take effect, the pertinent 30 

CFR 250, subpart Q pipeline 

decommissioning paperwork burden 

(3,000 burden hours) and their 

associated non-hour cost fees ($417,000) 

will be removed from the 1010–0142 

collection of information. 

There is a new paragraph (g) proposed 

for 30 CFR 256.62 which does impose 

a new information collection 

requirement. The paperwork burden for 

this proposed regulation is included in 

the submission to OMB for approval of 

the proposed 30 CFR 250 subpart J 

information collection. When this 

regulation becomes final, the 30 CFR 

256 paperwork burden would be 

removed from this collection of 

information and consolidated with the 

information collection burden for 30 

CFR 256 under OMB Control Number 

1010–0006. 

The following table provides a 

breakdown of the paperwork burden 

and fee estimates for this proposed 

rulemaking. For the current 

requirements retained in the proposed 

rule, we used the approved estimated 

hour burdens and the average number of 

annual responses where discernable. 

However, due to the vastly different 

structure of the proposed rule from 

current regulations, some adjustments 

(¥4,874 hours) occurred. The proposed 

rule eliminates four currently approved 

information collection requirements in 

current regulations at §§ 250.1000(c)(2), 

(4), (8); and 250.1016 for a minimal 

burden reduction (¥9 hours). However, 

there are several new requirements in 

the proposed rule as follows: 

• Most are procedures and practices 

that are currently being followed by 

respondents. However, their hour 

burdens are not identifiable in the OMB 

approval of current information 

collection estimates, and are therefore 

considered ‘‘new’’ information 

collection burdens (+67,293 hours). 

• Although a new Form MMS–153 is 

proposed for notifying MMS of pipeline 

installations or relocations and 

hydrostatic pressure tests, it should be 

noted that the information reported on 

the form is not a new burden (0 hours). 

• A proposed new section, Pipeline 

Risers Connected to Floating Platforms 

(§§ 250.1053–1056) would add new 

burden requirements (+8,100 hours). 

• When the rule takes effect, 

proposed § 250.1079 will require an 

initial one-time burden (+141,700 

hours) on current respondents to 

develop the operating procedures. In 

future years, this burden will be 

drastically reduced as only new 

respondents will have to develop their 

initial operating procedures. There will 

be a substantially lower ongoing burden 

to maintain and update the procedures 

annually (+15,260 hours). 

• Current subpart J regulations have 

107,874 hours approved by OMB. This 

revision to the collection requests a total 

of 337,884 hours which is a burden hour 

net increase of 230,010 hours. The fee 

is unchanged. 


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As part of our continuing effort to 

reduce paperwork and respondent 

burdens, MMS invites the public and 

other Federal agencies to comment on 

any aspect of the reporting and 

recordkeeping burden. You may submit 


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your comments directly to the Office of 

Information and Regulatory Affairs, 

OMB. You should provide MMS with a 

copy of your comments so that we can 

summarize all written comments and 

address them in the final rule preamble. 

Refer to the ADDRESSEES section for 

instructions on submitting comments. 

You may obtain a copy of our 

submission to OMB to revise and extend 

the OMB approval for 1010–0050 by 

contacting the Bureau’s Information 

Collection Clearance Officer at (202) 

208–7744. 

The PRA provides that an agency may 

not conduct or sponsor a collection of 

information unless it displays a 

currently valid OMB control number. 

Until OMB approves this collection of 

information and assigns an OMB control 

number and the regulations become 

final, you are not required to respond. 

OMB is required to make a decision 

concerning the collection of information 

of this proposed regulation between 30 

to 60 days after publication of this 

document in the Federal Register. 

Therefore, a comment to OMB is best 

assured of having its full effect if OMB 

receives it by November 2, 2007. This 

does not affect the deadline for the 

public to comment to MMS on the 

proposed regulations. 

MMS specifically solicits comments 

on the following questions: 

(a) Is the collection of information 

necessary for MMS to properly perform 

its functions, and will it be useful? 

(b) Are the estimates of the burden 

hours of the collection reasonable? 

(c) Do you have any suggestions that 

would enhance the quality, clarity, or 

usefulness of the information to be 

collected? 

(d) Is there a way to minimize the 

information collection burden on those 

who are to respond, including the use 

of appropriate automated electronic, 

mechanical, or other forms of 

information technology? 

In addition, the PRA requires agencies 

to estimate the total annual reporting 

and recordkeeping ‘‘non-hour cost’’

burden resulting from the collection of 

information. Other than the cost 

recovery fees listed in the table above, 

we have not identified any other costs, 

and we solicit your comments on this 

item. For reporting and recordkeeping 

only, your response should split the cost 

estimate into two components: (a) Total 

capital and start-up cost component, 

and (b) annual operation, maintenance, 

and purchase of services component. 

Your estimates should consider the 

costs to generate, maintain, and disclose 

or provide the information. You should 

describe the methods you use to 

estimate major cost factors, including 

system and technology acquisition, 

expected useful life of capital 

equipment, discount rate(s), and the 

period over which you incur costs. 

Generally, your estimates should not 

include equipment or services 

purchased: 

(1) Before October 1, 1995; 

(2) To comply with requirements not 

associated with the information 

collection; 

(3) For reasons other than to provide 

information or keep records for the 

Government; or 

(4) As part of customary and usual 

business or private practices. 

National Environmental Policy Act 

(NEPA) of 1969 

The MMS has determined that this 

proposed rule is categorically excluded 

under 516 Department Manual Chapter 

2, Appendix 1, 1.10, which covers 

‘‘Policies, directives, regulations, and 

guidelines that are of an administrative, 

financial, legal, technical, or procedural 

nature and whose environmental effects 

are too broad, speculative, or conjectural 

to lend themselves to meaningful 

analysis and will later be subject to the 

NEPA process, either collectively or 

case-by-case. 

This proposed rule would revise 

MMS’s regulations at 30 CFR parts 250, 

253, 254, and 256 and brings them upto-date with current industry practices 

and technology. It also incorporates 

several conditions of approval for 

pipelines, plus guidance from various 

Notices to Lessees and Operators and 

one Letter to Lessees and Operators into 

one set of comprehensive pipeline 

regulations. The proposed regulations 

also have been written in plain 

language. 

The changes to be implemented by 

this proposed rule are administrative, 

technical, and procedural in nature. The 

environmental effects of the proposed 

changes are either indirect (e.g., revised 

monitoring and reporting requirements), 

or too broad and speculative to lend 

themselves to a meaningful NEPA 

analysis. Individual pipelines and 

pipeline rights-of-way approved and 

regulated under this proposed rule will 

be subjected to the NEPA process. In 

addition, this proposed rule does not 

involve extraordinary circumstances as 

outlined in 516 DM 2, Appendix 2 that 

would trigger further NEPA analysis. 

Energy Supply, Distribution, or Use 

(Executive Order 13211) 

Executive Order 13211 requires the 

agency to prepare a Statement of Energy 

Effects when it takes a regulatory action 

that is identified as a significant energy 

action. This proposed rule is not a 

significant energy action, and therefore 

would not require a Statement of Energy 

Effects, because it: 

a. Is not a significant regulatory action 

under E.O. 12866, 

b. Is not likely to have a significant 

adverse effect on the supply, 

distribution, or use of energy, and 

c. Has not been designated by the 

Administrator of the Office of 

Information and Regulatory Affairs, 

Office of Management and Budget, as a 

significant energy action. 

Consultation With Indian Tribes 

(Executive Order 13175) 

Under the criteria in E.O. 13175, we 

have evaluated this proposed rule and 

determined that it has no potential 

effects on federally recognized Indian 

tribes. There are no Indian or tribal 

lands on the OCS. 

Clarity of This Regulation 

Executive Order 12866 requires each 

agency to write regulations that are easy 

to understand. MMS invites your 

comments on how to make this 

proposed rule easier to understand, 

including answers to questions such as 

the following: 

(1) Are the requirements in the 

proposed rule clearly stated? 

(2) Does the proposed rule contain 

technical language or jargon that 

interferes with its clarity? 

(3) Does the format of the proposed 

rule (grouping and order of sections, use 

of headings, paragraphing, etc.) aid or 

reduce its clarity? 

(4) Would the proposed rule be easier 

to understand if it were divided into 

more (but shorter) sections? 

(5) Is the description of the proposed 

rule in the SUPPLEMENTARY INFORMATION

section of this preamble helpful in 

understanding the rule? What else can 

we do to make the rule easier to 

understand? 

Send a copy of any comments that 

concern how we could make this rule 

easier to understand to: Office of 

Regulatory Affairs, Department of the 

Interior, Room 7229, 1849 C Street, 

NW., Washington, DC 20240. You may 

also e-mail the comments to this 

address: Exsec@ios.doi.gov. 

List of Subjects 

30 CFR Part 250 

Administrative practice and 

procedure, Continental shelf, 

Environmental impact statements, 

Environmental protection, Pipelines, 

Public lands—mineral resources, Public 

lands—rights-of-way, Reporting and 

recordkeeping requirements, Sulphur. 


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30 CFR Part 253 

Continental shelf, Environmental 

protection, Intergovernmental relations, 

Oil pollution, Pipelines, Public lands—

mineral resources, Reporting and 

recordkeeping requirements. 

30 CFR Part 254 

Continental shelf, Intergovernmental 

relations, Oil pollution, Pipelines, 

Public lands—mineral resources, 

Reporting and recordkeeping 

requirements. 

30 CFR Part 256 

Administrative practice and 

procedure, Continental shelf, 

Environmental protection, 

Intergovernmental relations, Public 

lands—mineral resources, Public 

lands—rights-of-way, Reporting and 

recordkeeping requirements, Surety 

bonds. 

Dated: August 3, 2007. 

C. Stephen Allred, 

Assistant Secretary—Land and Minerals 

Management. 

For the reasons stated in the 

preamble, Minerals Management 

Service (MMS) proposes to amend 30 

CFR parts 250, 253, 254, and 256 as 

follows: 

PART 250—OIL AND GAS AND 

SULPHUR OPERATIONS IN THE 

OUTER CONTINENTAL SHELF 

1. The authority citation for part 250 

continues to read as follows: 

Authority: 43 U.S.C. 1331 et seq., 31 U.S.C. 

9701. 

2. Amend § 250.105 as follows: 

A. Remove the definitions of ‘‘Lease 

term pipelines,’’ ‘‘Pipelines,’’ and 

‘‘Right-of-way pipelines.’’

B. Amend the definition of the term 

‘‘Affected State’’ by removing the word 

‘‘or’’ at the end of paragraph (4), 

removing the period at the end of 

paragraph (5) and adding a semicolon in 

its place, and adding new paragraphs (6) 

and (7). 

C. Add the definitions of 

‘‘Chemosynthetic communities,’’ ‘‘Lease 

term pipeline,’’ ‘‘Pipeline,’’ ‘‘Pipeline 

right-of-way (ROW),’’ ‘‘Pipeline ROW 

holder,’’ and ‘‘ROW pipeline’’ in 

alphabetical order. 

The additions read as follows: 

§ 250.105 Definitions. 

* * * * * 

Affected State * * * 

(6) Which is directly adjacent to the 

proposed route of a ROW pipeline; or 

(7) Which contains the onshore base 

you will use to provide supply and 

service support for ROW pipeline 

operations. 

* * * * * 

Chemosynthetic communities means 

assemblages of tubeworms, clams, 

mussels, bacterial mats, and a variety of 

associated organisms that obtain their 

energy from the oxidation of various 

organic compounds rather than from 

light (photosynthesis) and the sundependent photosynthetic food chain 

that supports all other life on earth. 

* * * * * 

Lease term pipeline means a pipeline 

that is applied for by a lessee or 

designated lease operator, and that is 

completely contained within the 

boundaries of a single lease, unitized 

leases, or contiguous (not cornering) 

leases held by that lessee or operated by 

that designated lease operator. 

* * * * * 

Pipeline means the horizontal 

components, risers, and appurtenances 

installed for transporting oil, gas, 

sulphur, and produced water. Piping 

confined to a production platform or 

structure, commonly referred to as a 

flowline, is regulated under subpart H of 

this part, Oil and Gas Production Safety 

Systems, and is excluded from this 

subpart. 

Pipeline right-of-way (ROW) means an 

authorization issued by MMS under the 

authority of section 5(e) of the OCSLA 

(43 U.S.C. 1334(e)) and section 8 of the 

OCSLA (43 U.S.C. 1337(p)(1)(B)) that 

allows for the construction and use of 

an associated ROW pipeline for the 

purpose of transporting oil, natural gas, 

or sulphur. The term also means the 

area covered by that authorization. 

Pipeline ROW holder means a person, 

association, or corporation that has been 

granted a pipeline ROW on the OCS by 

MMS under the authority of section 5(e) 

of the OCSLA (43 U.S.C 1334(e)) and 

section 8 of the OCSLA (43 U.S.C. 

1337(p)(1)(b)). 

* * * * * 

ROW pipeline means a pipeline that 

is within: 

(1) An unleased OCS block(s), or 

which crosses any portion of an 

unleased OCS block; 

(2) An OCS lease or unit, or which 

crosses any portion of an OCS lease or 

unit, and the applicant is not a lessee or 

the designated lease operator of that 

lease, or the unit operator of that unit. 

* * * * * 

3. Amend § 250.125(a) as follows: 

A. Remove the paragraphs (a)(20) 

through (a)(26); 

B. Remove paragraphs (a)(35) and 

(a)(36); 

C. Redesignate paragraphs (a)(27) 

through (a)(34) as paragraphs (a)(29) 

through (a)(36), respectively; and 

D. Add paragraphs (a)(20) through 

(a)(28) as set forth below. 

§ 250.125 Service fees. 

(a) * * * 

Service—processing of the following: Fee amount 30 CFR citation 

* * * * * * * 

(20) New Pipeline Application (Lease Term Pipeline) ............................................................................... $3,100 § 250.1014(g). 

(21) Pipeline Application-Modification (Lease Term Pipeline) ................................................................... $1,800 § 250.1093(b)(7). 

(22) Pipeline Application-Modification (ROW Pipeline) (includes the application to modify the associated Pipeline ROW Grant, if applicable).$3,650 § 250.1093(b)(7); 

§ 250.1132(a). 

(23) Pipeline Repair Application ................................................................................................................ $340 § 250.1095(a)(9). 

(24) Application to Decommission a Pipeline (Lease Term Pipeline) ....................................................... $1,000 § 250.1109(a)(1)(vii); 

§ 250.1109(a)(2)(xii). 

(25) Application for a New Pipeline ROW Grant (includes the application for the associated ROW 

pipeline and any application to install or establish an associated accessory).

$2,350 § 250.1125(b); 

§ 250.1126(h). 

(26) Application for a Pipeline ROW Grant (to convert a Lease Term Pipeline to an ROW Pipeline) ..... $200 § 250.1125(b); 

§ 250.1126(h). 

(27) Request to Assign a Pipeline ROW Grant ......................................................................................... $170 § 250.1134(a)(5). 

(28) Application to Relinquish a Pipeline ROW Grant (includes the decommissioning application for 

the associated ROW pipeline and any application to decommission an associated accessory).

$1,900 § 250.1136(a)(6). 

* * * * * * * 


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* * * * * 

4. Amend § 250.198 as follows: 

A. Redesignate paragraph (d)(7) as 

paragraph (a)(8) and add new paragraph 

(d)(7); 

B. In the table in paragraph (e), add 

entries in alphanumerical order for the 

following new documents incorporated 

by reference: API RP 1111 and DNV RP 

B401; and 

C. In the table in paragraph (e), revise 

the entries for the following documents 

incorporated by reference: ANSI/ASME 

B16.5, ANSI/ASME B31.8, API RP 2A–

WSD, API RP 2RD, API RP 14C, API RP 

500, API RP 505, API Spec 6A, API Spec 

6D/ISO 14313, API Spec 17J, and NACE 

MR0175. 

The additions and revisions read as 

follows: 

§ 250.198 Documents incorporated by 

reference. 

* * * * * 

(d) * * * 

For Write to 

* * * * * 

(7) DNV Recommended 

Practice.

Det Norske Veritas, 16340 

Park Ten Place, Houston, 

TX 77084. 

* * * * * 

(e) * * * 

Title of documents Incorporated by reference at 

* * * * * * * 

ANSI/ASME B16.5–2003 (including Errata) and B16.5a–2003 Addenda, 

Pipe Flanges and Flanged Fittings.

§ 250.1034(b)(1). 

ANSI/ASME B31.8–2003, Gas Transmission and Distribution Piping 

Systems.

§ 250.1033(a). 

* * * * * * * 

API RP 2A–WSD, Recommended Practice for Planning, Designing and 

Constructing Fixed Offshore Platforms-Working Stress Design; Twenty-first Edition, December 2002; Errata and Supplement 1, December 

2002; Errata and Supplement 2, October 2005; API Stock No. 

G2AWSD.

§ 250.901(a)(4); 

§ 250.908(a); 

§ 250.920(a), (b), (c), (e); 

§ 250.1033(k); 

§ 250.1141(a)(1)(ii), (iii); 

§ 250.1146(d). 

* * * * * * * 

API RP 2RD, Design of Risers for Floating Production Systems (FPSs) 

and Tension-Leg Platforms (TLPs), First Edition, June 1998, API 

Stock No. G02RD1.

§ 250.800(b); 

§ 250.901(a)(6); 

§ 250.1033(d). 

* * * * * * * 

API RP 14C, Recommended Practice for Analysis, Design, Installation, 

and Testing of Basic Surface Safety Systems for Offshore Production 

Platforms, Seventh Edition, March 2001, API Stock No. G14C07.

§ 250.802(b), (e)(2); 

§ 250.803(a), (b)(2)(i), (b)(4), (b)(5)(i), (b)(7), (b)(9)(v), (c)(2); 

§ 250.804(a), (a)(6); 

§ 250.1068(a)(1); 

§ 250.1080(c); 

§ 250.1084(a)(1), (b)(1), (c)(1), (d)(1), (d)(2), (e)(1); 

§ 250.1628(c), (d)(2); 

§ 250.1629(b)(2), (b)(4)(v); 

§ 250.1630(a). 

* * * * * * * 

API RP 500, Recommended Practice for Classification of Locations for 

Electrical Installations at Petroleum Facilities, Classified as Class I, 

Division 1 and Division 2, Second Edition, November 1997, reaffirmed November 2002, API Stock No. C50002.

§ 250.114(a); 

§ 250.459; 

§ 250.802(e)(4)(i); 

§ 250.803(b)(9)(i); 

§ 250.1064(b)(2); 

§ 250.1065(b)(2); 

§ 250.1066(b)(2); 

§ 250.1628(b)(3), (d)(4)(i); 

§ 250.1629(b)(4)(i). 

API RP 505, Recommended Practice for Classification of Locations for 

Electrical Installations at Petroleum Facilities, Classified as Class I, 

Zone 0, Zone 1, and Zone 2, First Edition, November 1997, reaffirmed November 2002, API Stock No. C50501.

§ 250.114(a); 

§ 250.459; 

§ 250.802(e)(4)(i); 

§ 250.803(b)(9)(i); 

§ 250.1064(b)(2); 

§ 250.1065(b)(2); 

§ 250.1066(b)(2); 

§ 250.1628(b)(3), (d)(4)(i); 

§ 250.1629(b)(4)(i). 

API RP 1111, Design, Construction, Operation, and Maintenance of 

Offshore Hydrocarbon Pipelines (Limit State Design), Third Edition, 

July 1999, Sections 4.1.6.2, 4.3.1, 4.3.1.1, 4.3.1.2, 4.3.2.1, 4.3.2.2, 

and 4.5.4 only, API Stock No. D11113.

§ 250.1033(a), (b), (c). 

* * * * * * * 

API Spec 6A, Specification for Wellhead and Christmas Tree Equipment, Nineteenth Edition, July 2004, API Stock No. GX06A19.§ 250.806(a)(3); 

§ 250.1034(a), (b)(1). 


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Title of documents Incorporated by reference at 

* * * * * * * 

API Spec 6D/ISO 14313, Specification for Pipeline Valves, Twenty-second Edition, January 2002, effective date July 1, 2002, API Stock 

No. G0X6D22.

§ 250.1034(a). 

* * * * * * * 

API Spec 17J, Specification for Unbonded Flexible Pipe, Second Edition, November 1999, effective date July 1, 2000, API Stock No. 

G17J02.

§ 250.803(b)(2)(iii); 

§ 250.1015(c)(5); 

§ 250.1016(b)(5); 

§ 250.1033(e). 

* * * * * * * 

DNV RP B401, Recommended Practice for Cathodic Protection Design, 1993, Table 6.9.1 only.§ 250.1034(d)(2). 

* * * * * * * 

NACE Standard MR0175, Metals for Sulfide Stress Cracking and 

Stress Corrosion Cracking Resistance in Sour Oilfield Environments, 

January 17, 2003, NACE Item No. 21302.

§ 250.490(p)(2); 

§ 250.901(a)(19); 

§ 250.1035. 

* * * * * * * 

5. In § 250.199, revise paragraph (e)(9) 

to read as follows: 

§ 250.199 Paperwork Reduction Act 

statements—information collection. 

* * * * * 

(e) * * * 

* * * * * * * 

(9) Subpart J, Pipelines and Pipeline Rights-of-Way (1010–0050), including Forms MMS–153, Notification of Pipeline Installation/Relocation/Hydrotest; MMS–2030, OCS Pipeline Right-of-Way Grant Bond; 

MMS–149, Assignment of Federal OCS Pipeline Right-of-Way Grant.

To provide MMS with information regarding the design, installation, and 

operation of pipelines on the OCS. To ensure that pipeline operations are safe and protect the human, marine, and coastal environment. 

* * * * * * * 

§§ 250.1100–1107 [REDESIGNATED] 

6. Redesignate §§ 250.1100–1107 as 

§§ 250.1150–1157. 

7. Revise subpart J to read as follows. 

Subpart J—Pipelines and Pipeline Rightsof-Way 

General 

250.1000 Definitions. 

250.1001 What general performance and 

recordkeeping requirements apply to 

OCS pipelines? 

250.1002 What are the types of OCS 

pipelines? 

250.1003 Which departments have 

jurisdiction over OCS pipelines? 

250.1004 What are the criteria for 

determining jurisdiction? 

250.1005 What are the requirements 

regarding jurisdiction transfer points? 

250.1006 When must I submit the 

applications, requests, plans and reports, 

and make the notifications required by 

this subpart? 

Applications for New Pipelines 

250.1007 How do I apply for approval of a 

new pipeline? 

250.1008 Where must I send copies of my 

pipeline application? 

250.1009 How does MMS process a 

pipeline application? 

250.1010 What conditions must my 

pipeline application meet? 

250.1011 What can I do if an affected State 

objects to my pipeline ROW application? 

250.1012 How will the Regional Supervisor 

notify me of the decision on my pipeline 

application? 

250.1013 When may the Secretary cancel 

approval of a pipeline application? 

Pipeline Application Contents 

250.1014 General information. 

250.1015 Other general information. 

250.1016 Information regarding other 

agencies and entities. 

250.1017 Location information. 

250.1018 Origination and termination 

information. 

250.1019 Horizontal component and 

appurtenances information. 

250.1020 Schematic flow diagram. 

250.1021 Shallow hazards information. 

250.1022 Construction information. 

250.1023 Onshore support base, terminal, 

support vessels, and aircraft information. 

250.1024 Operation information. 

250.1025 Service and products information. 

250.1026 Biological and archaeological 

information. 

250.1027 Requests for alternative 

compliance or departure. 

250.1028 Oil and hazardous substance spill 

response information. 

250.1029 Oil Spill Financial Responsibility 

(OSFR) demonstration information. 

250.1030 Environmental Impact Analysis 

(EIA) information. 

Pipeline Design 

250.1031 What are the general requirements 

for designing a pipeline? 

250.1032 What must I do to avoid or 

mitigate hazards? 

250.1033 What are the design requirements 

for horizontal components and risers? 

250.1034 What are the design requirements 

for appurtenances? 

250.1035 What are the design requirements 

for sewer service? 

250.1036 When must I sectionalize a 

pipeline? 

Pipeline Fabrication 

250.1038 What are the general requirements 

for fabricating a pipeline? 

Pipeline Construction 

250.1040 What are the general requirements 

for constructing a pipeline? 

250.1041 Who must I notify before I begin 

construction? 

250.1042 What must I do to avoid or 

mitigate hazards during construction? 

250.1043 What must I do to install a hot 

tap? 

250.1044 What must I do to protect a 

horizontal component? 

250.1045 What must I do to protect a riser? 

250.1046 What must I do to protect an 

appurtenance and crossing? 

250.1047 What must I do to construct a 

pipeline in or near a designated use area? 


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250.1048 What must I do to construct a 

pipeline in or near a sensitive biological 

feature or area? 

250.1049 What must I do to construct a 

pipeline in or near an archaeological 

resource? 

250.1050 When must I prepare and 

implement an H2S contingency plan for 

construction? 

250.1051 What information must I submit 

after construction is completed? 

Pipeline Risers Connected to Floating 

Platforms 

250.1052 What are the requirements for 

pipeline risers connected to floating 

platforms? 

250.1053 What are the requirements for 

pipeline riser verification plans? 

250.1054 What must the CVA do to verify 

pipeline riser design? 

250.1055 What must the CVA do to verify 

pipeline riser fabrication? 

250.1056 What must the CVA do to verify 

pipeline riser installation? 

Pipeline Pressure Testing 

250.1057 What are the general requirements 

for pressure testing a pipeline? 

250.1058 What are the requirements for 

conducting a hydrostatic pressure test for 

a pipeline? 

250.1059 What are the requirements for 

leak testing a pipeline? 

250.1060 When must I perform a pressure 

test on a pipeline? 

250.1061 What information must I include 

in a pressure test report? 

Pipeline Safety Equipment 

250.1062 What are the general requirements 

for pipeline safety equipment? 

250.1063 What are the safety equipment 

requirements for a departing pipeline? 

250.1064 What are the safety equipment 

requirements for an incoming pipeline? 

250.1065 What are the safety equipment 

requirements for a crossing pipeline? 

250.1066 What are the safety equipment 

requirements for a bi-directional 

pipeline? 

250.1067 When must I provide redundant 

safety equipment? 

250.1068 What are the safety equipment 

requirements for a pipeline pump? 

250.1069 What must I do if safety 

equipment fails to operate as intended? 

Pipeline Leak Detection 

250.1071 When do I need to use a leak 

detection system? 

Pipeline Internal Corrosion Control and 

Flow Assurance 

250.1074 What are the general requirements 

for internal corrosion control? 

250.1075 What are the general requirements 

for flow assurance? 

Pipeline Operations and Maintenance 

250.1078 What are the general requirements 

for operating and maintaining a 

pipeline? 

250.1079 What written procedures must I 

establish before I operate an OCS 

pipeline? 

250.1080 When must I mark the MMSassigned pipeline segment number on a 

pipeline? 

250.1081 How do I determine the MAOP of 

a pipeline? 

250.1082 What must I do if the pipeline 

transports H2S? 

250.1083 What are the requirements for 

conducting remote operations during a 

platform evacuation? 

250.1084 What are the requirements for 

testing pipeline safety equipment? 

250.1085 What must I do when safety 

equipment is removed from service? 

250.1086 What must I do when a pipeline 

is taken out of service? 

250.1087 What must I do if a pipeline is 

shut in? 

250.1088 What must I do if a pipeline 

leaks? 

250.1089 What must I do if I need to flare 

or vent gas from a pipeline? 

250.1090 When must I provide impact 

protection for existing risers? 

250.1091 When will MMS suspend or 

temporarily prohibit pipeline 

operations? 

Pipeline Modifications and Repairs 

250.1093 What must I do to modify an 

approved pipeline? 

250.1094 What are the general requirements 

for repairing a pipeline? 

250.1095 What must I do to commence and 

complete a repair? 

250.1096 What must I do to repair a 

pipeline using a clamp? 

250.1097 When do I need to submit a 

corrective action plan and report? 

Pipeline Surveying, Monitoring, and 

Inspection 

250.1100 What are the general requirements 

for surveying, monitoring, and 

inspecting a pipeline? 

250.1101 What must I do to survey and 

monitor a pipeline or route? 

250.1102 What inspections are required for 

my pipeline or route? 

250.1103 What additional inspections or 

surveys may the Regional Supervisor 

require? 

Pipeline Decommissioning 

250.1105 When do I accrue pipeline 

decommissioning obligations? 

250.1106 When must I decommission a 

pipeline? 

250.1107 What must I do to decommission 

a pipeline in place? 

250.1108 What must I do to decommission 

a pipeline by removal? 

250.1109 How do I obtain approval to 

decommission a pipeline? 

250.1110 How does MMS process a 

decommissioning application? 

250.1111 After I decommission a pipeline, 

what information must I submit? 

250.1112 When must I remove a pipeline 

decommissioned in place? 

250.1113 What are the requirements for recommissioning a decommissioned 

pipeline? 

Pipeline Right-of-Way (ROW) Grants 

250.1115 What is a pipeline ROW grant? 

250.1116 When must I obtain a pipeline 

ROW grant? 

250.1117 Who can be a pipeline ROW grant 

holder? 

250.1118 What are the financial security 

requirements for holding a pipeline 

ROW grant? 

250.1119 When will MMS terminate the 

period of liability of my financial 

security? 

250.1120 When will MMS cancel my 

financial security? 

250.1121 What happens if my financial 

security is reduced or lapses? 

250.1122 How will MMS determine that my 

financial security is forfeited? 

250.1123 What penalties can MMS assess if 

my financial security is not sufficient, is 

reduced or lapses, or is forfeited? 

250.1124 What happens to my financial 

security after a pipeline ROW grant 

terminates? 

250.1125 How do I submit an application 

for a pipeline ROW grant? 

250.1126 What information must I include 

in an application for a pipeline ROW 

grant? 

250.1127 How does MMS process an 

application for a pipeline ROW grant? 

250.1128 When will MMS temporarily 

suspend or prohibit construction of an 

ROW pipeline? 

250.1129 What must I do if the as-built 

location of the associated ROW pipeline 

deviates from the approved pipeline 

ROW grant? 

250.1130 What rental fees and payment 

schedules apply to a pipeline ROW 

grant? 

250.1131 What are the terms and conditions 

for holding a pipeline ROW grant? 

250.1132 How do I modify a pipeline ROW 

grant? 

250.1133 How does temporary cessation 

and cessation of pipeline operations 

affect a pipeline ROW grant? 

250.1134 How do I assign a pipeline ROW 

grant? 

250.1135 When may MMS suspend a 

pipeline ROW grant? 

250.1136 How do I relinquish a pipeline 

ROW grant? 

250.1137 When will a pipeline ROW grant 

be cancelled, be forfeited, or expire? 

250.1138 What must I do after a pipeline 

ROW grant terminates? 

Accessories to Right-of-Way (ROW) 

Pipelines 

250.1140 What are the requirements for an 

accessory to an ROW pipeline? 

250.1141 How do I obtain approval to 

install, operate, and maintain an 

accessory? 

250.1142 How does MMS process an 

accessory application? 

250.1143 Who do I need to notify before I 

install an accessory? 

250.1144 What information must I submit 

after an accessory is installed? 

250.1145 What accessory inspections must 

I conduct? 

250.1146 What must I do to modify an 

accessory? 

250.1147 When must I decommission an 

accessory? 


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Subpart J—Pipelines and Pipeline Rightsof-Way 

General 

§ 250.1000 Definitions 

Terms used in this subpart have the 

following meanings: 

Accessory means a platform, a major 

subsea manifold, or similar subsea 

structures attached to a ROW pipeline to 

support pump stations, compressors, 

manifolds, etc. The site used for an 

accessory is part of the pipeline ROW 

grant. 

Appurtenance means equipment, 

device, apparatus, or other object 

attached to or associated with a 

horizontal component or riser. 

Examples include anodes, valves, 

flanges, fittings, umbilicals, vortexinduced vibration (VIV) devices, subsea 

manifolds, templates, pipeline end 

modules (PLEM’s), pipeline end 

terminals (PLET’s), anode sleds, other 

sleds, and jumpers (other than jumpers 

connecting subsea wells to manifolds). 

Failure, when applied to a pipeline or 

safety system, means any condition of 

the pipeline or a safety system 

component that prevents the complete 

performance of its design and function. 

Horizontal component means a 

horizontal pipe that connects a pipeline 

riser, subsea wellhead or template, or 

pipeline to a pipeline riser, subsea 

wellhead or template, or pipeline 

(synonymous with the term ‘‘linepipe’’). 

Leak means the release of product 

from a pipeline. 

Live bottoms (low relief features) 

means sea grass communities; areas that 

contain biological assemblages 

consisting of sessile invertebrates and/or 

algae living upon and attached to 

naturally occurring hard or rocky 

formations with rough, broken, or 

smooth topography; and areas where a 

hard substrate and vertical relief may 

favor the accumulation of turtles, fishes, 

or other fauna. These features occur 

throughout the POCSR, in the Eastern 

Planning Area of the Gulf of Mexico, 

and in the Beaufort Sea in Alaska. 

Live bottoms (pinnacle trend features 

or seamounts) means small, isolated, 

low to moderate relief carbonate reef 

features; outcrops of unknown origin; or 

hard substrates exposed by erosion that 

provide surface area for the growth of 

sessile invertebrates and/or algae, and 

attract large numbers of fish. These 

features occur in an area of topographic 

relief throughout the POCSR and 

AKOCSR, and in the northeastern 

portion of the western GOMR. In the 

POCSR and AKOCSR, these features 

include rocky reefs, rock outcrops, 

pinnacles or seamounts. In the GOMR, 

these features include pinnacle trend 

features. 

Maximum allowable operating 

pressure (MAOP) means the highest 

operating pressure allowable at any 

point in a pipeline. 

Military warning or water test area 

means an area on the OCS that is used 

by the U.S. Department of Defense for 

conducting various mission operations, 

including air-to-air gunnery, rocket and 

missile research and testing, sonar buoy 

operations, pilot training, and aircraft 

carrier operations. 

New or unusual technology means 

equipment or procedures that have: 

(1) Not been used previously or 

extensively in an MMS OCS Region; 

(2) Not been used previously under 

the anticipated operating conditions; or 

(3) Operating characteristics that are 

outside the performance parameters 

established by this subpart. 

Potentially sensitive biological 

features means those features not 

protected by an MMS biological lease 

stipulation that are of moderate to high 

relief (about 8 feet or higher), provide 

surface area for the growth of sessile 

invertebrates, and attract large numbers 

of fish. These features would be located 

outside any ‘‘No Activity Zone’’ of any 

of the named topographic features and 

would not be located on any live-bottom 

(pinnacle trend) stipulated blocks. 

Production platform means a platform 

on the OCS that receives hydrocarbon or 

sulphur production either directly from 

wells or from other platforms that 

produce hydrocarbons or sulphur from 

wells. It may include processing 

equipment for treating the production or 

separating it into its various liquid and 

gaseous components. 

Riser means a vertical conducting 

pipe that connects a horizontal 

component of a pipeline to equipment 

on a platform. 

Splash zone means that portion of a 

pipeline riser that is located between 20 

feet above the maximum tide and 20 feet 

below the minimum tide. 

Topographic features means 

identified isolated areas of moderate to 

high relief that provide habitat for hardbottom communities and numerous 

plant and animal species, and support, 

either as shelter or food, large numbers 

of commercially and recreationally 

important fishes. 

§ 250.1001 What general performance and 

recordkeeping requirements apply to OCS 

pipelines? 

(a) Performance. You must design, 

construct, operate, maintain, inspect, 

and decommission all OCS pipelines, 

appurtenances, accessories, and safety 

system components in a manner that: 

(1) Conforms to the OCSLA (43 U.S.C. 

1331, et seq.), as amended, applicable 

implementing regulations, other 

applicable laws, approved applications, 

approved Development Operations 

Coordination Documents (DOCD) and 

Development and Production Plans 

(DPP), and lease provisions and 

stipulations; 

(2) Is safe; 

(3) Prevents unauthorized discharges; 

(4) Does not unreasonably interfere 

with other uses of the OCS, including 

those involved with national security or 

defense; and 

(5) Does not cause undue or serious 

harm or damage to the human, marine, 

or coastal environment. 

(b) Records. You must retain all 

records related to the design, 

construction, operation, maintenance, 

testing, inspections, repairs, failures, 

and decommissioning of an OCS 

pipeline for as long as the pipeline 

remains in place, unless otherwise 

specified by the Regional Supervisor or 

in these regulations, and make them 

available to MMS upon request. 

§ 250.1002 What are the types of OCS 

pipelines? 

An OCS pipeline is either a lease term 

pipeline or an ROW pipeline. 

§ 250.1003 Which departments have 

jurisdiction over OCS pipelines? 

An OCS pipeline is under the 

jurisdiction of either the Department of 

the Interior (DOI) or the Department of 

Transportation (DOT). 

§ 250.1004 What are the criteria for 

determining jurisdiction? 

(a) DOI jurisdiction criteria. An OCS 

pipeline is under DOI jurisdiction if it 

is: 

(1) A lease term pipeline that is not 

subject to regulation under 49 CFR, 

parts 192 and 195, and does not cross 

into State waters; or 

(2) An ROW pipeline that is operated 

by an identified pipeline operator (the 

person or entity identified by the 

pipeline ROW holder as authorized to 

control or manage the pipeline’s 

operations), and that is either: 

(i) A producing pipeline operator (the 

identified pipeline operator of an ROW 

pipeline that is a lessee or designated 

lease operator of one or more OCS 

leases), unless it is subject to regulation 

under 49 CFR, parts 192 and 195, and 

crosses into State waters; or 

(ii) A transporting pipeline operator 

(the identified pipeline operator of an 

ROW pipeline that is not a lessee or a 

designated lease operator of an OCS 

lease), and the pipeline is not subject to 

regulation under 49 CFR, parts 192 and 

195. 


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(b) DOT jurisdiction criteria. An OCS 

pipeline that is not under DOI 

jurisdiction (see paragraph (a) of this 

section) is under DOT jurisdiction. 

(c) Jurisdiction transfer. You may 

request that a pipeline under DOI 

jurisdiction be transferred to DOT 

jurisdiction, or that a pipeline under 

DOT jurisdiction be transferred to DOI 

jurisdiction, by submitting a written 

petition for approval to the Regional 

Supervisor and the DOT Office of 

Pipeline Safety (OPS) Regional Director. 

In the petition, you must provide 

sufficient justification for the transfer. 

The Regional Supervisor and the DOT 

OPS Regional Director will decide 

jointly whether to approve the petition. 

§ 250.1005 What are the requirements 

regarding jurisdiction transfer points? 

(a) Jurisdiction transfer point. For 

each applicable pipeline, you must meet 

the requirements of this paragraph (a). 

(1) You must identify the specific 

point at which regulatory jurisdiction 

transfers from DOI to DOT, or from DOT 

to DOI, by: 

(i) Durably marking an above-water 

jurisdiction transfer point or, if that is 

not practical, identifying the transfer 

point on a schematic; or 

(ii) Identifying an underwater 

jurisdiction transfer point on a 

schematic. 

(2) You must keep the schematics 

referenced in paragraph (a)(1) of this 

section at the nearest OCS facility and 

make them available to MMS upon 

request. 

(b) Jurisdiction transfer point 

disagreement. If the lessee(s), 

designated lease operator(s), or pipeline 

ROW holder(s) of connecting pipelines 

cannot agree upon a transfer point, the 

Regional Supervisor and the DOT OPS 

Regional Director will jointly determine 

the jurisdiction transfer point. 

§ 250.1006 When must I submit the 

applications, requests, plans and reports, 

and make the notifications required by this 

subpart? 

(a) Applications and requests. For all 

OCS pipelines you must submit 

applications to MMS, and receive 

approvals, according to the following 

table: 

Application or request Required by When to submit Total number of copies 

(1) Transfer jurisdiction ........ § 250.1004(c) ..................... Before jurisdiction can be transferred from DOI to 

DOT, or from DOT to DOI.

1 to MMS. 

1 to OPS. 

(2) New pipeline .................. § 250.1007(a) ..................... Before you install, maintain, or operate a new pipeline 3 

(3) Modify a pipeline ............ § 250.1093(a), (b) .............. Before you conduct operations to modify a pipeline .... 3 

(4) Repair a pipeline ............ § 250.1095(a) ..................... Before you conduct any repair work on a pipeline ....... 1 

(5) Decommission a pipeline 

in place.

§ 250.1109(a)(1) ................ Before you conduct operations to decommission a 

pipeline in place.

3 

(6) Decommission a pipeline 

by removal.

§ 250.1109(a)(2) ................ Before you conduct operations to decommission a 

pipeline by removal.

3 

(7) Re-commission a decommissioned pipeline.§ 250.1113(a)(1) ................ Before you re-commission a decommissioned pipeline 1 

(8) Accessory ....................... § 250.1141(a) ..................... Before you install, operate, and maintain an accessory 

to an ROW pipeline.

3 

(9) Modify an accessory ...... § 250.1146 ......................... Before you conduct operations to modify an accessory 3 

(10) Decommission an accessory—Initial.§ 250.1147 (see 

§ 250.1726).

In the POCSR and AKOCSR, at least 2 years before 

you decommission an accessory.

1 

(11) Decommission an accessory—Final.§ 250.1147 (see 

§ 250.1727).

Before you decommission an accessory ...................... 2 

(b) Pipeline ROW grant applications 

and requests. For ROW pipelines, you 

must submit the following applications 

and requests to MMS, and receive 

approvals, in addition to those listed in 

paragraph (a) of this section: 

Application or 

request Required by When to submit Total number of copies 

(1) Obtain a pipeline ROW 

grant.

§ 250.1125(a) ..................... Before you install, maintain, or operate an ROW pipeline.1 original and 2 copies. 

(2) Modify a pipeline ROW 

grant.

§ 250.1132(a) ..................... Before you can modify a pipeline ROW grant .............. 1 original and 2 copies. 

(3) Assign a pipeline ROW 

grant.

§ 250.1134(a) ..................... Before you can assign a pipeline ROW grant .............. 2 executed originals. 

(4) Relinquish a pipeline 

ROW grant.

§ 250.1136(a) ..................... Before you can relinquish a pipeline ROW grant ......... 1 original and 2 copies. 

(c) Notifications. You must make 

notifications to MMS according to the 

following table: 

Notification Under section When to notify 

(1) Pipeline construction ................. § 250.1041(a), using Form MMS–

153.

At least 48 hours before you commence pipeline construction. 

(2) Discovery of archaeological resource.§ 250.1049(d) ................................. Immediately. 

(3) Hydrostatic pressure test ........... § 250.1058(b), using Form MMS–

153.

At least 48 hours before you conduct a hydrostatic pressure test on a 

pipeline. 


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Notification Under section When to notify 

(4) Safety equipment failure or removal.§§ 250.1069(b) and 250.1085(a) ... In the GOMR, when the safety equipment remains out of service for 

12 hours. Immediately in the POCSR and AKOCSR. 

(5) Corrective action ........................ § 250.1069(d) ................................. Immediately when you repair or replace safety equipment and resume operating the pipeline, or when you have provided an equivalent degree of protection and resume operating the pipeline. 

(6) Return safety equipment to 

service.

§ 250.1085(c) ................................. Immediately when you return out-of-service safety equipment to service or when you provide an equivalent degree of protection. 

(7) Pipeline leak .............................. § 250.1088(b) ................................. Immediately or as soon as practicable after you discover that a pipeline has leaked. 

(8) Pipeline relocation ..................... § 250.1093(e), using Form MMS–

153.

At least 48 hours before you begin the work to relocate a pipeline. 

(9) Lapse of financial security for a 

pipeline ROW grant.

§ 250.1121(b) ................................. Within 72 hours after the security lapses. 

(10) Sabotage or subversive activity § 250.1131(k) ................................. Immediately upon discovery. 

(d) Plans and Reports. You or the 

Certified Verification Agent (CVA), as 

appropriate, must submit plans and 

reports to MMS according to the 

following table: 

Plan/Report Under section When to submit Total number of 

copies 

(1) Pipeline construction, including pressure 

test results.

§ 250.1051(a) ............. Within 45 calendar days after you complete 

pipeline construction.

3 

(2) Design verification plans for pipeline risers 

connected to floating platforms.

§ 250.1053(a) ............. At least 30 calendar days before you submit 

the associated pipeline application.

1 

(3) Fabrication verification plans for pipeline 

risers connected to floating platforms.

§ 250.1053(b) ............. At least 30 calendar days before you submit 

the associated pipeline application.

1 

(4) Installation verification plans for pipeline 

risers connected to floating platforms.

§ 250.1053(c) .............. At least 30 calendar days before you submit 

the associated pipeline application.

1 

(5) Interim CVA reports for pipeline risers connected to floating platforms.§ 250.1054(c); 

§ 250.1055(d); ............

§ 250.1056(d) .............

CVA submits during each verification phase .. 1 

(6) Final CVA design reports for pipeline risers 

connected to floating platforms.

§ 250.1054(d) ............. CVA submits within 90 calendar days of receipt of the design data, or within 90 calendar days after MMS approval to act as a 

CVA, whichever is latest, and before fabrication begins.

1 

(7) Final CVA fabrication reports for pipeline 

risers connected to floating platforms.

§ 250.1055(e) ............. CVA submits within 90 calendar days after 

completion of fabrication, and before installation.

1 

(8) Final CVA installation reports for pipeline 

risers connected to floating platforms.

§ 250.1056(e) ............. CVA submits within 45 calendar days after 

pipeline installation.

1 

(9) Directed pressure test ................................ § 250.1060(d) ............. As directed by the Regional Supervisor ......... As directed by the Regional Supervisor. 

(10) Out-of-service pipeline .............................. § 250.1086(d) ............. Within 48 hours after a pipeline is deemed to 

be out of service.

1 

(11) Out-of-service pipeline reactivation, including pressure test results.§ 250.1086(g) ............. Within 30 calendar days after you reactivate 

a pipeline that has been out of service.

1 

(12) Flaring/venting operations ........................ § 250.1089(b) ............. Within 72 hours after completing flaring or 

venting operations.

1 

(13) Pipeline modification, including pressure 

test results.

§ 250.1093(f) .............. Within 30 calendar days after you complete 

the pipeline modification.

1 

(14) Pipeline repair, including pressure test results.§ 250.1095(e) ............. Within 30 calendar days after you complete a 

repair.

1 

(15) Flexible joint inspections ........................... § 250.1102(b) ............. Within 30 calendar days after you complete 

the inspection.

1 

(16) Pipe-to-electrolyte potential measurements.§ 250.1102(d) ............. No later than October 31 of the same year, 

or within 60 calendar days of the measurements, whichever is earlier.

1 

(17) Additional inspections and surveys .......... § 250.1103(a) through 

(f).

As directed by the Regional Supervisor ......... 1 

(18) Pipeline decommissioning ........................ § 250.1111 .................. Within 30 calendar days after you complete 

the decommissioning.

1 

(19) Decommissioned pipeline re-commissioning, including pressure test results.§ 250.1113(b) ............. Within 30 calendar days after you complete 

the re-commissioning.

1 

(20) Accessory installation ............................... § 250.1144 .................. Within 45 calendar days after you complete 

accessory installation.

3 

(21) Accessory inspections .............................. § 250.1145(a)(2) ......... By November 1 of each year .......................... 1 

(22) Accessory decommissioning .................... § 250.1147 (see 

§ 250.1729).

Within 30 calendar days after you decommission an accessory.2 


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Plan/Report Under section When to submit Total number of 

copies 

(23) Accessory site clearance .......................... § 250.1147 (see 

§ 250.1743(b)).

Within 30 calendar days after you conduct 

site clearance verification operations.

2 

Applications for New Pipelines 

§ 250.1007 How do I apply for approval for 

a new pipeline? 

Before you install, maintain, or 

operate a new pipeline (including a 

jumper), or a pipeline you create with 

a combination of new pipe and existing 

pipe, you must submit three copies of a 

pipeline application to the Regional 

Supervisor for approval. If you prefer to 

submit all or part of your pipeline 

application electronically (see 

§ 250.186(a)(3)), you should consult 

with the Regional Supervisor for further 

guidance. 

(a) Application contents. (1) Your 

application must include the 

information described in §§ 250.1014 

through 250.1030. 

(2) The Regional Supervisor may 

require you to include additional 

information, if necessary, to assist in 

evaluating your pipeline application. 

(3) The Regional Director may require 

less information or analysis than you 

otherwise must provide in your pipeline 

application when: 

(i) Sufficient information or analysis 

is readily available to MMS; 

(ii) Other coastal or marine resources 

are not present or affected; or 

(iii) Other factors, such as 

technological advances, affect 

information needs. 

(b) Where to submit the application. 

You must submit a pipeline application 

to one of the MMS Regional offices 

shown in the following table. 

For OCS areas adjacent to the . . . Submit your application to . . . 

(1) State of Alaska .................................................................................... Minerals Management Service, Alaska OCS Region (AKOCSR), Regional Supervisor, Field Operations. 

(2) Atlantic Coast States and in the Gulf of Mexico ................................ Minerals Management Service, Gulf of Mexico OCS Region (GOMR), 

Regional Supervisor, Field Operations. 

(3) States of California, Oregon, Washington, or Hawaii ......................... Minerals Management Service, Pacific OCS Region (POCSR), Chief, 

Office of Facilities, Safety & Enforcement. 

(c) Withdrawal after submission. You 

may withdraw your pipeline application 

at any time, and for any reason, by 

notifying the Regional Supervisor in 

writing. 

§ 250.1008 Where must I send copies of 

my pipeline application? 

(a) Impacted leases and pipeline ROW 

grants. When you submit a pipeline 

application to MMS, you must provide 

a copy of the pipeline application to 

each lessee or designated lease operator 

of an existing lease, and to each holder 

of a pipeline ROW grant (active or 

terminated) that could be impacted by 

your proposed pipeline construction or 

towing operations. 

(b) Affected States. Unless the 

proposed operations described in your 

pipeline application are under a general 

concurrence from the affected State, 

when you submit a new ROW pipeline 

application to MMS you must provide 

each affected State with all of the 

following: 

(1) A copy of the pipeline application. 

Pursuant to 43 CFR part 2, Appendix E, 

MMS has determined that none of the 

information included in an ROW 

pipeline application is proprietary. 

Therefore, you must not exclude any 

information from the copies of the 

application you submit to affected 

States. 

(2) A consistency certification (see 15 

CFR 930.57). 

(3) All necessary data and information 

(see 15 CFR 930.58). 

§ 250.1009 How does MMS process a 

pipeline application? 

The Regional Supervisor determines 

whether the application is complete, 

accurate, and fulfills the requirements of 

this subpart. If the Regional Supervisor 

determines that your application does 

not meet these conditions, the Regional 

Supervisor will notify you of the 

problem or deficiency. The Regional 

Supervisor will not begin final review of 

your application until it is complete. 

(a) Compliance review. The Regional 

Supervisor will ensure that your 

proposed operations conform to the 

OCSLA (43 U.S.C.1331, et seq.), as 

amended; other applicable laws; and 

applicable MMS regulations. 

(b) Environmental impact evaluation. 

The Regional Supervisor will evaluate 

the environmental impacts of your 

proposed operations, and prepare 

environmental documentation under 

NEPA (42 U.S.C. 4321, et seq.) and its 

implementing regulations (40 CFR parts 

1500 through 1508). 

(c) Amendments. During the review of 

your pipeline application, the Regional 

Supervisor may require you, or you may 

elect, to change your pipeline 

application. 

§ 250.1010 What conditions must my 

pipeline application meet? 

The Regional Supervisor will approve 

your pipeline application only if you 

satisfy all of the criteria in this section. 

(a) You must obtain the Regional 

Supervisor’s approval of either a DOCD 

or DPP that covers the structure at the 

originating end of the pipeline (e.g., 

platform, well, subsea skid), if the 

proposed pipeline is a lease term 

pipeline (see § 250.1015(b)). 

(b) You must provide the Regional 

Supervisor with a copy of your 

approved State permit (see 

§ 250.1016(c)), if the proposed pipeline 

will enter or cross any State submerged 

lands. 

(c) If the proposed pipeline will enter 

or cross any safety fairway or anchorage 

area, you must provide the Regional 

Supervisor with a copy of your 

approved U.S. Army Corps of Engineers 

permit (see § 250.1016(d)). 

(d) If an OCS lease or pipeline ROW 

grant could be impacted by your 

proposed pipeline construction or 

towing operations (see § 250.1016(e) and 

(f)), you must: 

(1) Provide the Regional Supervisor 

with a return receipt or letter of no 

objection from the lessee or designated 

lease operator of each impacted lease, or 

the holder of each impacted pipeline 

ROW grant (active or terminated); and 

(2) Ensure that each entity you 

notified under paragraph (d)(1) of this 

section had at least 30 days from the 


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date they received the pipeline 

application from you to submit 

comments to the Regional Supervisor. 

(e) If the proposed pipeline will 

terminate or originate at a new hot tap 

or other connection on the OCS, the 

lessee, designated lease operator, or 

pipeline ROW holder of the receiving or 

delivering pipeline must first obtain 

approval from the Regional Supervisor 

to modify their pipeline. 

(f) For ROW pipeline and new 

accessory installation applications, 

either: 

(1) All affected States with approved 

CZMA programs have concurred, or 

have been conclusively presumed to 

concur, with your coastal zone 

consistency certification in your 

pipeline application under section 

307(c)(3)(A) of the Coastal Zone 

Management Act (CZMA) (16 U.S.C. 

1456(c)(3)(A)); or 

(2) The Secretary of Commerce finds, 

under section 307(c)(3)(A) of the CZMA 

(16 U.S.C.1456(c)(3)(A)), that the 

proposed ROW pipeline operations or 

new accessory installation are 

consistent with the objectives of CZMA, 

or are otherwise necessary in the 

interest of national security. 

(g) For ROW pipeline applications, 

you must demonstrate oil spill financial 

responsibility (OSFR) as required by 30 

CFR 253.13, if applicable (see 

§ 250.1029). 

§ 250.1011 What can I do if an affected 

State objects to my ROW pipeline 

application? 

For ROW pipeline and new accessory 

installation applications, if an affected 

State objects to the coastal zone 

consistency certification in your 

application, you may follow the 

procedures in either paragraph (a) or (b) 

of this section. 

(a) You may amend your application 

to accommodate the State’s objection, 

and submit the amendment to the 

Regional Supervisor for approval and to 

the affected State for its consistency 

determination. The amendment need 

only address information related to the 

State’s objection. 

(b) You may appeal the State’s 

objection to the Secretary of Commerce 

using the procedures in 15 CFR part 

930, subpart H. The Secretary of 

Commerce will either: 

(1) Grant your appeal by finding, 

under section 307(c)(3)(B)(iii) of CZMA 

(16 U.S.C. 1456(c)(3)(B)(iii)) that the 

proposed operations are consistent with 

the objectives of CZMA, or are 

otherwise necessary in the interest of 

national security; or 

(2) Deny your appeal, in which case 

you may either amend your application 

under paragraph (a) of this section or 

withdraw your application and not 

conduct the proposed operations. 

§ 250.1012 How will the Regional 

Supervisor notify me of the decision on my 

pipeline application? 

After review and evaluation, the 

Regional Supervisor will notify you in 

writing whether your pipeline 

application is approved or disapproved. 

(a) The Regional Supervisor will 

approve your pipeline application if it 

complies with all applicable 

requirements; and will inform you of 

any conditions that you may be required 

to meet. In the approval letter, the 

Regional Supervisor will assign a 

unique MMS pipeline segment number 

that you must use in all subsequent 

correspondence regarding the pipeline. 

(b) The Regional Supervisor will 

disapprove your pipeline application if 

the proposed operations would probably 

cause serious harm or damage (and you 

cannot amend the proposed pipeline 

operations to avoid such conditions) to 

life (including fish or other aquatic life), 

property, any mineral (in areas leased or 

not leased), the national security or 

defense, or the marine, coastal, or 

human environment. The Regional 

Supervisor will provide the reason(s) for 

disapproving your pipeline application 

in writing. 

§ 250.1013 When may the Secretary cancel 

approval of a pipeline application? 

The Secretary may cancel approval of 

your pipeline application upon your 

request, or if pipeline operations under 

the application are in suspension or 

temporary prohibition (see § 250.1091) 

for at least 5 years (see section 5(a)(2) of 

the OCSLA (43 U.S.C. 1334(a)(2)). To 

cancel approval under this section, the 

Secretary must determine after a hearing 

that all of the following conditions are 

met: 

(a) Continued operation under the 

approved pipeline application would 

probably cause serious harm or damage 

to life (including fish and other aquatic 

life), property, mineral resources (in 

areas leased or not leased); the national 

security or defense, or the marine, 

coastal, or human environment; 

(b) The threat of harm or damage will 

not disappear or decrease to an 

acceptable extent within a reasonable 

period of time; and 

(c) The advantages of cancellation 

outweigh the advantages of continuing 

the pipeline application in force. 

Pipeline Application Contents 

§ 250.1014 General information. 

You must provide the following 

general information: 

You must provide a(n). . . That includes. . . and. . . 

(a) Cover letter ..................... (1) The name of the company and the name, title, and 

signature of the company representative filing the application; and.

(2) A statement that you are applying for approval of 

the pipeline in accordance with § 250.1007.

(b) List of contacts ............... The name and MMS operator number of the company 

filing the application, and the company’s managerial, 

regulatory, and technical representatives who the Regional Supervisor can contact while processing the 

application.

For each contact, you must include the: 

(1) Company name; 

(2) Business and postal address; 

(3) Telephone number; 

(4) Telefax number; and 

(5) E-mail address. 

(c) Indication of the pipeline 

type.

An indication whether the proposed pipeline will be a 

lease term pipeline type or an ROW pipeline.

(d) Indication of the pipeline 

jurisdiction.

An indication whether the proposed pipeline will be 

under the jurisdiction of DOI or DOT.

If you wish petition to transfer jurisdiction from DOI to 

DOT or to transfer jurisdiction from DOT to DOI (see 

§ 250.1004(b)), you may include the request in your 

pipeline application. 

(e) Tentative schedule for 

conducting pipeline operations.

The date your installation operations will begin and end The date you will place the pipeline into service. 


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You must provide a(n). . . That includes. . . and. . . 

(f) New or unusual technology statement.A statement whether you will or will not use a new or 

unusual technology to carry out your proposed pipeline operations.

If you will use new or unusual technology, provide a 

narrative description of the technology and the rationale for its selection. 

(g) Payment ......................... Payment of a nonrefundable service fee (see § 250.125 

for amount).

If the application is for a lease term pipeline. 

§ 250.1015 Other general information. 

If your proposed pipeline operations 

meet any of the criteria in the following 

table, you must provide the indicated 

information: 

If. . . You must provide. . . 

(a) You are applying for an ROW pipeline ............................................... A statement that certifies that you have an approved National Pollutant 

Discharge Elimination System (NPDES) permit, or that you have applied for an NPDES permit that covers your proposed pipeline operations. 

(b) You are applying for lease term pipeline in the GOMR ..................... The MMS assigned control number for the DOCD or DPP that a covers 

or will cover your proposed pipeline operations. If you have not submitted the DOCD or DPP, you must provide the date you intend to 

submit the document or plan to the GOMR. 

(c) You are applying for an ROW pipeline and you propose to use 

measures beyond those required by this part to minimize or mitigate 

environmental impacts.

A description of the additional measures you will use. 

(d) Your pipeline will operate in a sour environment ............................... A certification that the pipeline is designed in accordance with the requirements in § 250.1035. 

(e) You will install a supervisory control and data acquisition(SCADA) 

system.

A brief description of the system. 

§ 250.1016 Information regarding other 

agencies and entities. 

If your proposed pipeline operations 

meet any of the criteria in the following 

table, you must provide the indicated 

information: 

For each . . . You must provide . . . 

(a) ROW pipeline and new accessory installation ................................... (1) Coastal zone consistency certification according to 15 CFR 930.57 

for each affected State; and 

(2) Evidence that you sent your pipeline or accessory application, consistency certification (see 15 CFR 930.57), and all necessary data 

and information (see 15 CFR 930.58) to each affected State for their 

CZMA consistency determination. 

(b) ROW pipeline, if the routes of the vessels and aircraft you will use 

to support your proposed pipeline operations are located in or could 

traverse established military warning or water test areas.

(1) An identification of the warning and water test area(s); and 

(2) A certification that, before you begin pipeline construction operations, you will contact the military installation with jurisdiction over 

the area concerning the control of electromagnetic emissions and the 

use of vessels and aircraft in the area. 

(c) Proposed pipeline that will enter into or cross State offshore waters A copy of the approved permit from that State.1

(d) Proposed pipeline that will enter into or cross any safety fairway or 

anchorage area.

A copy of the approved U.S. Army Corps of Engineers permit.1

(e) Proposed pipeline that will enter into an existing OCS lease, or 

whose construction operations could impact lease operations (e.g., 

placing anchors on the lease).

OCS area and block designations, OCS lease number, and name of 

the lessee or designated lease operator for each impacted lease. 

(f) Proposed pipeline that will cross, or whose construction operations 

could impact an existing ROW pipeline or a decommissioned pipeline 

(i.e., placing anchors or routing the pipeline across or within 500 feet 

of an existing ROW pipeline).

OCS area and block designations of the crossing or impact point, and 

name of the pipeline ROW holder. 

(g) Proposed pipeline that will originate or terminate at an existing 

valve or hot tap assembly.

(1) OCS area and block designations of the tie-in point(s); and 

(2) Name of the lessee or designated lease operator if a connecting 

pipeline is a lease term pipeline; or the name of the pipeline ROW 

holder if a connecting pipeline is an ROW pipeline. 

(h) Proposed pipeline you identified pursuant to paragraphs (e), (f), and 

(g) of this section.

A photocopy of a return receipt or a letter of no objection that indicates 

the date that the lessee, designated lease operator, or pipeline ROW 

holder received a copy of your pipeline application by registered or 

certified mail (or equivalent).1

1 If this document is not available when you submit your application, you may submit the document later. 


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§ 250.1017 Location information. 

(a) You must provide the following 

location information: 

You must provide . . . That must . . . 

(1) A location plat based on the North American Datum of 1927 (NAD 

27) for the GOMR (Gulf) and POCSR, and the North American 

Datum of 1983 (NAD 83) for the AKOCSR and GOMR (Atlantic), with 

a minimum scale of 1 inch = 2,000 feet.

Include the information listed in paragraph (b) of this section. 

(2) An Electronic file of the digital coordinates of a sufficient number of 

points to provide an accurate representation of the entire route of the 

proposed pipeline, including turns and umbilicals.

Be in decimal degree latitude and longitude and based on NAD 27 for 

the GOMR (Gulf) and POCSR, and NAD 83 for the AKOCSR and 

GOMR (Atlantic). The Regional Supervisor will specify the file format 

for providing this information. 

(3) Information on the proposed locations of the origin, termination, and 

inclusive OCS blocks traversed by the pipeline route.

Include, if applicable, the OCS area, block number, and lease number. 

(4) The total length (feet) of the proposed pipeline excluding risers, the 

length in Federal waters (feet), and the length in State waters (feet), 

if applicable.

(b) The location plat required by 

paragraph (a)(1) of this section must do 

all of the following: 

(1) Identify the lessee, designated 

lease operator, or pipeline ROW holder. 

(2) Show OCS area, block, and lease 

designations. 

(3) Show the pipeline route from 

origination to termination, including the 

plant or refinery, if applicable. It must 

also show flow direction and, if an ROW 

pipeline, the 200-foot pipeline ROW 

and any site for an accessory. 

(4) Show the routes and flow 

directions of all umbilicals. 

(5) Identify all platforms (including 

accessories) and pipelines (MMSassigned segment numbers) that your 

proposed pipeline will connect to, 

cross, or otherwise impact. 

(6) Identify all safety fairways, 

anchorage areas, and military warning 

or water test areas that are within 500 

feet of the center line of the proposed 

pipeline. 

(7) Show the burial depth (feet) of the 

pipeline along its entire length. 

(8) Show the water depth (feet) along 

the entire length of the pipeline. 

(9) Depict the water depth (feet), X–

Y coordinates, and decimal degree 

latitude and longitude of each of the 

following key points: 

(i) Locations of the originating and 

terminating structures; 

(ii) Points where the proposed 

pipeline crosses a fairway, an anchorage 

area, or a lease or block boundary; 

(iii) Locations of subsea valves, 

flanges, hot taps, tie-ins, anode sleds, 

connecting sleds (including PLEM’s and 

PLET’s), manifolds (including those that 

are accessories), and other 

appurtenances; 

(iv) Locations of pipeline crossings; 

(v) Points throughout the curvature of 

a turn; and 

(vi) Point where the pipeline enters 

into State jurisdiction, if applicable. 

(10) Include a certification by a 

registered engineer or land surveyor that 

the information on the plat is accurately 

represented. 

(c) For each ROW pipeline, you must 

provide a map at an appropriate scale 

that shows the: 

(1) Proposed pipeline route relative to 

the shoreline, the onshore support base 

you will use, and the proposed primary 

transportation routes for your support 

vessels and aircraft; and 

(2) Distance to shore (miles) of the 

pipeline route origination and 

termination points. 

§ 250.1018 Origination and termination 

information. 

You must provide origination and 

termination information as indicated in 

the following table: 

Type of information When required Contents 

(a) General information on the facilities where the proposed pipeline will originate and terminate.In all cases .................................... (1) The type of structure (i.e., platform, well jacket or caisson, subsea 

well, manifold, tie-in, or blind flange); 

(2) MMS-assigned name of the structure (if applicable); 

(3) OCS area and block designations; 

(4) OCS lease number (if applicable); 

(5) Distance to shore (miles); 

(6) Water depth (feet); 

(7) Whether the structure is manned or unmanned; and 

(8) If the facility is equipped with a pig launcher/receiver, a description of its major features and rating. 

(b) Riser design information for 

each pipe diameter.

If the pipeline will connect at a 

platform, well jacket, or caisson.

(1) Design life (years); 

(2) Outside diameter (inches); 

(3) Wall thickness (inches); 

(4) Pipe grade; 

(5) Hydrostatic test pressure (psi) and duration (hours); 

(6) Type and thickness (mils) of the external corrosion coating; 

(7) Type and thickness (mils) of the external corrosion coating in the 

splash zone; 

(8) Type and thickness (mils) of the internal corrosion coating; 

(9) Type of riser, e.g., fixed, catenary, top tension, flexible; 

(10) Type, pressure rating (psi), and, if applicable, the de-rated pressure rating (psi) of the insulating flange; and 

(11) Whether the riser can be inspected using in-line inspection tools 

(e.g., smart pigs). 


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Type of information When required Contents 

(c) Non-traditional pipe .................... If you plan to use any non-traditional pipe (e.g., flexible pipe) to 

construct the riser.

(1) The name and a description of the non-traditional pipe; 

(2) The manufacturer’s design specification sheet; 

(3) The design pressure (psi); 

(4) An identification of the design standards you used; and 

(5) A review by a third-party verification agent (specified in API Spec 

17J (incorporated by reference as specified in § 250.198), where 

applicable) if you intend to use any unbonded flexible pipe. 

(d) Riser guard design .................... In all cases .................................... A drawing that shows how you will protect the riser(s) from physical 

damage that could result from contact with floating vessels. 

(e) Catenary and other non-traditional riser.If the riser will be a catenary or 

other non-traditional design.

(1) Design fatigue life (years) of the riser and the fatigue point at 

which you would replace the riser; 

(2) Identification of the design standards you used; and 

(3) Type and rating of the connecting device you will use; 

(f) Subsea manifold ......................... If the proposed pipeline will originate or terminate at a subsea 

manifold.

A diagram of the facility showing its major features including: 

(1) Pressure rating (psi) of the pressure limiting component; 

(2) Type of exterior protective coating; and 

(3) Description of the cathodic protection system. 

(g) Subsea tie-in .............................. If the proposed pipeline will originate or terminate at a subsea 

tie-in.

Information about the tie-in that includes: 

(1) Type of tie-in assembly (existing valve or new hot tap); 

(2) MMS-assigned pipeline segment number of the delivering or receiving pipeline; 

(3) MAOP (psi) of the delivering or receiving pipeline; and 

(4) Schematic drawing of the tie- in assembly. 

(h) Subsea blind flange ................... If the pipeline will originate or terminate at a subsea blind flange.Information about the blind flange that includes the: 

(1) Type; 

(2) Pressure rating (psi); and 

(3) If applicable, the de-rated pressure rating (psi). 

(i) Other appurtenances and other 

accessories.

If the pipeline will include any 

equipment, device, apparatus, 

or other object not described in 

paragraphs (e) through (h) of 

this section.

Information about the appurtenance that includes: 

(1) Description of the appurtenance; 

(2) Schematic drawings showing the arrangement and orientation of 

the appurtenances; and 

(3) For subsea manifolds, pipeline end modules (PLEM’s), and pipeline end terminals (PLET’s), a diagram of the appurtenance showing its major features and dimensions, pressure rating (psi), and 

type of exterior protective coating, and a description of the cathodic 

protection system. 

§ 250.1019 Horizontal component and 

appurtenances information. 

You must provide horizontal 

component and appurtenances 

information as indicated in the 

following table: 

Type of information When required Required data elements 

(a) Pipeline internal design pressure.For all pipelines ............................. (1) Internal design pressure (psi) you calculated; 

(2) Formula you used to calculate the internal design pressure; 

(3) Design factors you used in calculating the internal design pressure; and 

(4) Calculations you performed to derive the internal design pressure 

for each pipe diameter and wall thickness. 

(b) Pipeline collapse design pressure.For all pipelines to be installed in 

water depths greater than 1000 

feet.

(1) External pressure on the pipe in (psi); 

(2) Collapse design pressure (psi) you calculated; 

(3) Formula you used to calculate the external design pressure; 

(4) Collapse factor you used in calculating the external design pressure; 

(5) Calculations you performed to derive the external design pressure 

for each pipe diameter and wall thickness; and 

(6) Description of any collapse arrestors you intend to install or other 

mitigation you intend to use. 


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Type of information When required Required data elements 

(c) Horizontal component design .... For all pipelines, for each pipe diameter incorporated in the horizontal component of the pipeline.(1) Design life (years); 

(2) Pipe outside diameter (inches); 

(3) Pipe wall thickness (inches); 

(4) Pipe grade; 

(5) Bare pipe and weighted pipe specific gravities, and a statement 

(based on stability analysis) that the pipeline will remain stable following installation; 

(6) Type of welds (e.g., longitudinal, electrical resistance welded 

(ERW), submerged arc welded (SAW), seamless); 

(7) Hydrostatic test pressure (psi) and test duration (hours); 

(8) Type and thickness (mils) of the external corrosion coating; 

(9) Type and thickness (mils) of the internal corrosion coating; 

(10) Density (pounds/cubic foot) and thickness (inches) of the concrete weight coating; and 

(11) Statement indicating whether or not the pipe can be inspected 

using in-line inspection tools (e.g., smart pigs). 

(d) Non-traditional pipe ................... If you plan to use any non-traditional pipe (e.g., coiled tubing, 

flexible pipe, unbonded flexible 

pipe) to construct the horizontal 

component.

(1) Name and a description of the non-traditional pipe; 

(2) Manufacturer’s design specification sheet; 

(3) Design pressure (psi); 

(4) Identification of the design standards you used; and 

(5) Review by a third-party independent verification agent (specified 

in API Spec 17J (incorporated by reference as specified in 

§ 250.198), where applicable) if you intend to use any unbonded 

flexible pipe. 

(e) Pipeline cathodic protection system.If you plan to install a cathodic 

protection system that uses 

bracelet anodes.

(1) Anode composition; 

(2) Design anode life expectancy (years); 

(3) Formula and calculations you used to determine the design life of 

your anodes; 

(4) Anode consumption rate (pounds/amp/year); 

(5) Net weight per anode (pounds); 

(6) Anode interval (feet); and 

(7) Number of anodes. 

(f) Non-traditional cathodic protection system.If you plan to install a cathodic 

protection system that does not 

use bracelet anodes.

(1) Specify and describe the system; and 

(2) Provide the applicable information from paragraph (e) of this section, and the information and calculations you used to show that 

your pipeline is cathodically protected. 

(g) Pipeline valves and flanges ....... If you plan to install a valve or 

flange on the horizontal component (not at the originating or 

terminating points) as an appurtenance to the pipeline.

Information about each valve or flange that includes the: 

(1) Type; 

(2) Pressure rating (psi); and 

(3) If applicable, the de-rated pressure rating (psi). 

(h) Umbilicals .................................. If you plan to install umbilicals as 

appurtenances to the pipeline.

A drawing that shows: 

(1) Types of umbilicals (e.g., electrical, hydraulic, chemical) you plan 

to install; 

(2) Configuration of the umbilicals in the bundle; 

(3) Length (feet) and outside diameter (inches) of the bundle; and 

(4) Any associated umbilical termination assemblies. 

(i) Other appurtenances .................. If you plan to install any equipment, device, apparatus, or 

other object not described in 

paragraphs (e) through (h) of 

section.

Information about each appurtenance that includes: 

(1) Description of the appurtenance; 

(2) Schematic drawings showing the arrangement and orientation of 

the appurtenances; and 

(3) For subsea manifolds, pipeline end modules (PLEM’s), and pipeline end terminals (PLET’s), a diagram of the appurtenance showing its major features and dimensions, pressure rating (psi), type of 

exterior protective coating, and a description of the cathodic protection system. 

(j) Pipeline crossings ....................... If the pipeline will cross any existing pipeline, umbilical, power or 

communication cable, or other 

structure or object.

(1) MMS-assigned segment number of the pipeline or umbilical (if applicable) to be crossed; 

(2) OCS area and block designations of the crossing location; 

(3) Description of the method you will use to separate the pipeline 

from the existing structure or object and the separation distance 

(inches); 

(4) Water depth (feet) at the pipeline crossing; 

(5) Indication of the presence or absence of H2S in the crossed pipeline; and 

(6) Diagram that shows a profile of the crossing that includes the 

depth of cover (feet). 

§ 250.1020 Schematic flow diagram. 

You must provide a schematic flow 

diagram of the proposed pipeline that is 

consistent with the diagram(s) required 

by § 250.802(e)(1) through (3), as 

appropriate, and that shows: 

(a) All pressure sensing devices and 

associated control lines; 


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(b) All pressure safety valves (PSVs) 

and settings; 

(c) All shutdown valves (SDVs), flow 

safety valves (FSVs), and block valves; 

(d) All pressure-regulating devices 

(including back-pressure regulators); 

(e) Any subsea manifolds, PLEMs and 

PLETs, and other appurtenances; 

(f) Input source(s) (e.g., wells, pumps, 

compressors, and vessels) and the 

maximum source pressure (MSP) (psi) 

of each; 

(g) Flow direction (or predominate 

direction for bi-directional flow); 

(h) Safety equipment for the input 

source; 

(i) Rated working pressure (psi) of all 

valves and flanges; 

(j) Any specification (spec) breaks; 

(k) Initial receiving equipment, vessel, 

or pipeline, and its rated working 

pressure (psi) or MAOP (psi); 

(l) Pig launchers and receivers; 

(m) Calculated MAOP (psi) of the 

proposed pipeline; 

(n) MMS-assigned segment number 

and approved MAOP (psi) of any 

connecting pipeline; and 

(o) The transfer point where 

jurisdiction changes between DOI and 

DOT, if applicable. 

§ 250.1021 Shallow hazards information. 

You must provide information on 

shallow hazards as indicated in the 

following table: 

Type of information When required Contents 

(a) Shallow hazards survey report .. For ROW pipelines in the GOMR, 

and for all pipelines in the 

POCSR and AKOCSR.

Shallow hazards survey report of the proposed pipeline route based 

on information obtained from the shallow hazards survey (see 

§ 250.1032(a)). The Regional Supervisor will specify requirements 

for preparing the report. 

(b) Shallow hazards analysis of any 

seafloor and subsurface geologic 

features, and any manmade features or conditions, which may 

have an adverse effect on the 

proposed pipeline.

In all cases .................................... (1) Description of the hazards along the pipeline route; 

(2) Discussion of any special safety measures you will take to minimize the adverse effects of shallow hazards on the proposed pipeline; and 

(3) Discussion of how you will comply with the hazard mitigation requirements specified in § 250.1042. 

§ 250.1022 Construction information. 

You must provide pipeline 

construction information as indicated in 

the following table: 

Type of information When required Contents 

(a) Installation method .................... In all cases .................................... A brief description of the method you will use to install the proposed 

pipeline (e.g., S-lay, J-lay, reeled lay, towed lay). 

(b) General information on the vessel/equipment you will use to 

construct the proposed pipeline.

In all cases .................................... (1) Type of vessel (e.g., anchor supported, dynamic positioning) or 

equipment (e.g., trucks, bulldozers); 

(2) Name of the vessel (if known); 

(3) Maximum anchor radius (feet); 

(4) Capacity of fuel tanks (barrels); and 

(5) Proposed anchor location for operations in the POCSR. 

(c) Tow route ................................... If you plan to install the pipeline by 

towing or dragging it to the installation site.

(1) Plat that depicts the entire tow route and indicates where the 

pipeline will be dragged on the seafloor, if applicable. 

(2) Electronic file containing the the digital coordinates of sufficient 

points to provide an accurate representation of the proposed tow 

route. In preparing this file, you must: 

(i) Use the file format specified by the Regional Supervisor; 

(ii) Include the data for the entire tow route; and 

(iii) Present the data in decimal degree latitude and longitude, based 

on NAD 27 for the GOMR (Gulf) and the POCSR, and NAD 83 for 

AKOCSR and GOMR (Atlantic). 

(3) Shallow hazards survey report for the tow route (see 

§ 250.1032(a)). 

(4) Analysis of any seafloor and subsurface geologic features, and 

any manmade features or conditions, which may have an adverse 

effect on the pipeline if towed or dragged. The analysis must include a: 

(i) Discussion of the hazards along the pipeline tow route; 

(ii) Description of any special safety measures you will take to minimize the adverse effects of shallow hazards on the towing operations; and 

(iii) Discussion of how you will comply with the hazard mitigation requirements specified in § 250.1042. 


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Type of information When required Contents 

(d) Air emissions ............................. For ROW pipelines in the GOMR, 

and for all pipelines in the 

POCSR and AKOCSR, you 

must provide air emissions information for all combustion 

sources used in pipeline construction operations.

(1) Total rated output (horsepower) of each vessel/equipment; 

(2) Rated output (horsepower) of each combustion emission source 

on the vessel(s) and a description of its use (e.g., crane, compressor, generator, dehydrator); 

(3) Run time (hours/day and days/year) for each emission source; 

(4) Documentation of any emission control technologies you will employ; and 

(5) Maximum hourly, daily, and total projected emissions for all pipeline installation-related emission sources. 

(e) Vessel discharges ..................... For ROW pipelines in the GOMR, 

and for all pipelines in the 

POCSR and AKOCSR, you 

must provide information on discharges for all vessels associated with your pipeline installation.

(1) Types and general characteristics of the wastes that will be generated and discharged into the ocean during construction operations; 

(2) Volume (gallons) of waste that will be discharged; 

(3) Average and maximum discharge rates (gallons/hour); 

(4) Description of any treatment or storage; and 

(5) Discharge location and method for each type of discharge. 

(f) Pipeline burial ............................. If you plan to bury the pipeline 

(see § 250.1044(c)).

(1) Method you will use to bury the pipeline (e.g., jet, plow); and 

(2) Depth of burial (feet), including the depths in safety fairways and 

anchorage areas. 

(g) Pipeline self burial ..................... If you expect that the pipeline will 

bury itself naturally in the sediment, you must provide a request to use an alternative procedure under § 250.141.

(1) Appropriate site-specific geotechnical data (e.g., sediment compaction, shear strength) and other information to verify sediment 

conditions; and 

(2) Information specified in § 250.1027(a). 

(h) Obstruction protection ............... In all cases .................................... Information concerning any covering (e.g., dome, cage, sandbags, 

concrete mats) you will use to protect a manifold, tie-in, or blind 

flange at the pipeline origination and termination points, and all 

valves, flanges, other appurtenances, and pipeline crossings along 

the horizontal component of the pipeline (see § 250.1046(a)). The 

information you provide must include: 

(1) A drawing that shows the specifications of the protective covering 

and the equipment it will protect; 

(2) A drawing and a description of the relationship of the protective 

covering to the seafloor (e.g., mat edges buried); 

(3) A discussion of any anchor pins or sandbags you will use to hold 

the protective covering in place, if applicable; 

(4) A description of the cathodic protection system for the protective 

covering, if appropriate; and 

(5) A discussion of your plans for maintaining the protective covering. 

(i) Underwater vent pipelines .......... If you plan to install an underwater 

vent pipeline.

A description of the provisions you will make for anchoring the end of 

the underwater vent pipeline. 

§ 250.1023 Onshore support base, 

terminal, support vessels, and aircraft 

information. 

You must provide information on 

each onshore base you will use to 

provide supply and service support for 

your proposed pipeline operations as 

indicated in the following table: 

Type of information When required Contents 

(a) Onshore support base ............... In all cases .................................... (1) Name and location of the onshore support base, and whether it 

will be a new or existing facility; 

(2) Description of the necessary work, if you plan to construct a new 

onshore support base or make major additions to an existing one; 

and 

(3) Timetable for land acquisition (including rights-of-way and easements) and construction or expansion if you plan to acquire land to 

construct a new facility or expand an existing one. 

(b) Onshore terminal ....................... For pipelines that will transport 

product to shore.

The name, description, and location of the primary onshore terminal 

(including any refinery, gas plant, or compressor station) that will 

be built or undergo expansion or major modification as the result of 

your proposed pipeline operations. 

(c) Support vessels and aircraft 

(general).

For ROW pipelines in the GOMR, 

and all pipelines in the POCSR 

and AKOCSR.

Information for each type of vessel/equipment (e.g., anchor-handling 

boats, tug boats, supply boats, service boats, crew boats) and aircraft you will use to support your proposed pipeline operations that 

includes: 

(1) Fuel tank storage capacity (barrels); 

(2) Maximum number of vessels/equipment that will be in the area of 

operations at any one time; and 

(3) Trip frequency or duration. 


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Type of information When required Contents 

(d) Diesel oil supply vessel/equipment.For ROW pipelines in the GOMR, 

and all pipelines in the POCSR 

and AKOCSR.

Information on the vessels you will use to supply diesel oil to your 

pipeline installation vessels/equipment that includes: 

(1) Vessel length (feet); 

(2) Diesel oil storage capacity (barrels); and 

(3) Frequency of fuel transfers. 

§ 250.1024 Operation information. 

You must provide the following 

pipeline operation information: 

(a) Pipeline operating temperature. 

The anticipated maximum and 

minimum operating temperatures (°F) of 

the proposed pipeline. 

(b) Proposed MAOP. Your proposed 

MAOP (psi) for the pipeline, and the 

method you used to determine the 

MAOP (see § 250.1081). 

§ 250.1025 Service and products 

information. 

You must indicate the primary service 

and, if applicable, the secondary service 

of the proposed pipeline (e.g., oil, bulk 

oil, natural gas, bulk gas, condensate, 

gas and condensate, gas lift, instrument, 

flare/vent, water, methanol, glycol, 

sulphur, or other chemicals). If the 

pipeline will be bidirectional, you must 

provide the service for each direction 

and indicate which one will 

predominate. 

If you will be primarily 

transporting . . . Then you must provide . . . The Regional Supervisor may also require . . . 

(a) Natural gas ................................ (1) The anticipated maximum flow 

rate (MMCFD); 

(2) The maximum design flow rate 

(MMCFD); 

(3) The specific gravity of the gas; 

(4) The carbon dioxide (CO2) and 

hydrogen sulfide (H2S) concentrations (ppm); 

(5) Your provisions for controlling 

internal corrosion; and 

(6) Your provisions for flow assurance 

The chemical and physical characteristics of the gas. 

(b) Liquid hydrocarbons .................. (1) The anticipated maximum flow 

rate (BPD); and 

(2) The maximum design flow rate 

(BPD); 

(3) The API° gravity of the liquid; 

(4) The anticipated CO2 and H2S 

concentrations (ppm); 

(5) Your provisions for controlling 

internal corrosion; and 

(6) Your provisions for flow assurance 

The chemical and physical characteristics of the oils (see definition 

under 30 CFR 254.6). 

(c) Chemicals .................................. (1) The anticipated maximum flow 

rate (BPD); 

(2) The maximum design flow rate 

(BPD); 

(3) Your provisions for controlling 

internal corrosion 

The chemical and physical characteristics of each chemical. 

(d) A product with an H2S concentration greater than 20 ppm, 

or will cross a pipeline that transports a product with an H2S concentration greater than 20 ppm.

(1) An H2S Contingency Plan prepared according to § 250.490(f); 

(2) A reference to an approved or 

submitted H2S Contingency Plan 

that covers the operation of the 

proposed pipeline and/or the 

construction operations at the 

pipeline crossing; or 

(3) A statement that you will submit for approval to the appropriate District Manager either an 

H2S Contingency Plan(s) or an 

amendment to an approved H2S 

Contingency Plan(s) before you 

install the proposed pipeline. 

(e) A product with an H2S concentration greater than 500 ppm.Two (2) copies of an H2S dispersion modeling report or the 

modeling results (see 

§ 250.1082(b)), or a reference to 

such report or results if already 

submitted to the Regional Supervisor. 


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§ 250.1026 Biological and archaeological 

information. 

You must provide the biological and 

archaeological information indicated in 

the following table: 

Type of information When required Contents 

(a) Chemosynthetic communities 

report.

If the proposed pipeline, or the associated anchors or chains of 

the pipeline construction vessel 

(or a proposed accessory, or the 

associated anchors or chains of 

the construction barge) will be 

placed in water depths 1,312 

feet or greater.

Three copies of a high-density chemosynthetic communities report. 

The Regional Supervisor will specify the contents of this report. 

(b) Sensitive biological features reports or documentation.If the proposed pipeline, or the associated anchors or chains of 

the pipeline construction vessel 

(or a proposed accessory platform, or the associated anchors 

or chains of the construction 

barge) will be placed in the vicinity of any biologically-sensitive features, including but not 

limited to topographic features, 

live bottoms (low-relief features), 

live bottoms (pinnacle trend features or seamounts), and potentially sensitive biological features.

Plats, a photo documentation survey report, and/or a high-resolution 

geophysical data survey report to identify and locate the features. 

The Regional Supervisor will specify when you must provide these 

plats and reports, and their contents. 

(c) Archaeological report ................. If you propose bottom-disturbing 

operations in areas that are 

identified as high probability 

shipwreck blocks or prehistoric 

areas.

Three copies of an archaeological report, or a reference to such a report if it was already provided to the Regional Supervisor. The Regional Supervisor will specify the contents of the archaeological report. 

§ 250.1027 Requests for alternative 

compliance or departure. 

You must provide any request for 

alternative compliance or departure as 

indicated in the following table: 

Type of request When required What your request must do 

(a) Alternative compliance ... You must request approval from the Regional Supervisor if you plan to use any alternate procedures or 

equipment (see § 250.141).

(1) Identify the MMS regulation for which you are seeking alternative compliance; 

(2) Describe the procedure, method, or equipment you 

plan to use; 

(3) Explain the reason you want to use the procedure, 

method, or equipment; and 

(4) Explain how you will achieve a level of safety and 

environmental protection that is equal to or greater 

than that prescribed by the MMS regulation. 

(b) Departure ........................ You must request approval from the Regional Supervisor if you plan to depart from any current MMS regulatory requirements (see § 250.142) concerning the 

proposed pipeline.

(1) Identify the MMS regulation for which you are seeking to forego or delay compliance; 

(2) Describe the procedure, method, or equipment you 

plan to use, if applicable; and 

(3) Explain the reason you wish to forego or delay compliance with the identified MMS regulation. 

§ 250.1028 Oil and hazardous substance 

spill response information. 

You must provide the following oil 

and hazardous substance spill response 

information: 

(a) Oil spill response planning. For 

ROW pipelines, you must provide 

either: 

(1) An Oil Spill Response Plan (OSRP) 

for the pipeline prepared according to 

the requirements of 30 CFR part 254; or 

(2) A reference to your approved 

regional or subregional OSRP (see 30 

CFR 254.3) that includes: 

(i) A discussion of your regional or 

subregional OSRP, and a statement that 

your proposed ROW pipeline operations 

will be covered by that OSRP; 

(ii) The locations of your primary oil 

spill equipment base and any 

preplanned equipment staging areas; 

(iii) The names of your oil spill 

removal organizations for both spill 

response equipment and personnel; 


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(iv) The calculated volume (barrels) of 

your worst case discharge scenario (see 

30 CFR 254.26(a)) for your proposed 

ROW pipeline; 

(v) A comparison of the above worst 

case discharge scenario with the 

applicable worst case discharge scenario 

in your approved regional or 

subregional OSRP; and 

(vi) A discussion of your worst case 

discharge scenario and your response in 

adverse weather conditions for your 

proposed operations (see 30 CFR 

254.26(b), (c), (d) and (e)). 

(b) Modeling report. If you model a 

potential oil or hazardous substance 

spill, a modeling report, the modeling 

results, or a reference to such report or 

results if you already submitted it to the 

Regional Supervisor. 

(c) Flower Garden Banks National 

Marine Sanctuary (FGBNMS). If you 

propose to conduct operations within 

the protective zones of the FGBNMS, a 

description of your provisions for 

monitoring the impacts of an oil spill on 

the environmentally sensitive resources 

at the FGBNMS. 

§ 250.1029 Oil Spill Financial 

Responsibility (OSFR) demonstration 

information. 

For ROW pipelines that will transport 

oil (see definition at 30 CFR 253.3), you 

must provide a statement that you have 

demonstrated or will demonstrate OSFR 

coverage in the amount specified in 30 

CFR 253.13(b) unless the static volume 

of the pipeline is 1,000 barrels, or less, 

or the calculated volume of your worst 

case discharge scenario is 1,000 barrels 

or less. 

§ 250.1030 Environmental Impact Analysis 

(EIA) information. 

For ROW pipelines, you must provide 

a project-specific EIA that identifies and 

analyzes the potential direct and 

indirect environmental impacts of your 

proposed ROW pipeline operations 

(including the installation and operation 

of any accessory) to assist the Regional 

Supervisor in complying with NEPA (42 

U.S.C. 4321, et seq.) and other relevant 

Federal laws. Your EIA must include: 

Type of information What must be included 

(a) Resources, conditions, and activities that 

could affect or be affected by your proposed 

ROW pipeline operations.

(1) Meteorology, oceanography, geology, and geological and/or manmade hazards; 

(2) Air and water quality; 

(3) Benthic communities, marine mammals, sea turtles, coastal and marine birds, fish and 

shellfish, and algal or plant life; 

(4) Threatened or endangered species, and their critical habitat, as defined by the Endangered 

Species Act (ESA) of 1973 (16 U.S.C. 1531, et seq.); 

(5) Sensitive biological resources or habitats such as essential fish habitat, refuges, preserves, 

special management areas identified in coastal management programs, sanctuaries, coastal 

monuments, national natural landmarks, rookeries, and calving grounds; 

(6) Archaeological resources; 

(7) Socio-economic resources, as specified in paragraph (b) of this section; 

(8) Coastal and marine uses, such as military or commercial operations, shipping, and mineral 

exploration or development; and 

(9) Other resources, conditions, and operations identified by the Regional Supervisor. 

(b) Socio-economic resources ............................ (1) The approximate number, timing, and duration of employment of persons engaged in onshore support and construction operations; 

(2) Population (including the approximate number of people and families added to local onshore areas); 

(3) Existing offshore and onshore infrastructure (including major sources of supplies, services, 

energy, and water); 

(4) Types of contractors or vendors that may place a demand on local goods and services; 

(5) Land use; 

(6) Subsistence resources and harvest practices; 

(7) Recreation and recreational and commercial fishing (including seasons, location, and type); 

(8) Minority and lower income groups; 

(9) Federally-recognized tribes in the AKOCSR; and 

(10) Coastal zone management programs. 

(c) Impact producing factors (IPF) that can 

cause impacts to the environmental resources you identified in paragraph (a) of this 

section.

(1) Air emissions; 

(2) Seafloor disturbance from anchoring and structure emplacement; 

(3) Discharges; 

(4) Emissions of light and noise; 

(5) Water intakes and discharges; 

(6) Use of service vessels and helicopters; 

(7) Construction or expansion of onshore support facilities; 

(8) Onshore waste disposal; and 

(9) Accidental events, including oil or chemical spills and hydrogen sulfide (H2S) releases. 

(d) Environmental impact analysis (EIA) ............ (1) Analysis of the direct and indirect impacts (including those from accidents) of the IPFs you 

identified in paragraph (c) of this section on the environmental resources, conditions, and 

activities you identified in paragraph (a) of this section; 

(2) Analysis of the potential cumulative impacts from other activities to those environmental resources, conditions, and activities you identified in paragraph (a) of this section; 

(3) Description of the type, severity, and duration of the potential impacts, and their biological, 

physical, and other consequences and implications; 

(4) Description of the potential measures to minimize or mitigate the potential impacts; and 

(5) Description of the alternatives to your proposed ROW pipeline operations that you considered while developing your pipeline application, and a comparison of the potential environmental impacts. 

(e) Consultation .................................................. A list of agencies and persons that you consulted or you will consult, regarding potential impacts associated with your proposed pipeline operations. 

(f) References cited ............................................ A list of the references that you cite in the EIA. 


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Pipeline Design 

§ 250.1031 What are the general 

requirements for designing a pipeline? 

You must design a pipeline, including 

the horizontal component, risers, valves, 

flanges, fittings, umbilicals, and all 

other appurtenances to do all of the 

following: 

(a) Mitigate any reasonably 

anticipated detrimental effects of water 

currents, storm or ice scouring, soft or 

hard bottoms, mud slides, earthquakes, 

hurricanes, subfreezing temperatures, 

and other environmental factors; 

(b) Withstand the anticipated 

maximum differential pressure to 

prevent both burst and collapse; 

(c) Withstand the static and dynamic 

loads that will be imposed on the pipe 

during construction and under 

operating conditions; 

(d) Mitigate the effects of thermal 

expansion and contraction; and 

(e) Mitigate the effects of internal and 

external corrosion. 

§ 250.1032 What must I do to avoid or 

mitigate hazards? 

(a) Shallow hazards survey. You must 

conduct a shallow hazards survey using 

appropriate high-resolution geophysical 

survey techniques and other tools to 

locate potential hazards. The Regional 

Supervisor will specify the survey area, 

instrumentation, and methodology. 

(b) Route selection. You must use the 

results of the shallow hazards survey 

required by paragraph (a) of this section, 

charts, maps, and other sources of 

relevant information to: 

(1) Select a route that avoids surface 

and subsurface hazards as much as 

possible (e.g., in anchorage areas, 

existing pipelines, other manmade 

objects, active faults, rock outcrops, 

mudslide areas); and 

(2) Identify hazards that you cannot 

avoid, and design the pipeline to 

mitigate the effects of these hazards. 

§ 250.1033 What are the design 

requirements for horizontal components 

and risers? 

(a) Internal design pressure. (1) You 

must determine the internal design 

pressure for steel horizontal 

components and risers using the 

following formula or the equations in 

section 4.3.1 of API RP 1111 and, if 

applicable, sections 4.3.1.1 and 4.3.1.2 

of API RP 1111 (incorporated by 

reference as specified in § 250.198): 

P S t

D = FET × ×

× ×

2 ( )

Variable Description 

P ....................... Internal design pressure (psi). 

S ....................... Specified minimum yield strength (psi), stipulated in the specification under which the pipe was purchased from the manufacturer or determined in accordance with section 811.253(h) of ANSI/ASME B31.8 (incorporated by reference as specified in 

§ 250.198). 

T ....................... Nominal wall thickness (inches). 

D ....................... Nominal outside diameter of pipe (inches). 

F ....................... Construction design factor (0.72 for the horizontal component and 0.60 for risers). 

E ....................... Longitudinal joint factor from Table 841.1B of ANSI/ASME B31.8 (incorporated by reference as specified in § 250.198) (See 

also section 811.253(d) of this standard). 

T ....................... Temperature derating factor obtained from Table 841.1C of ANSI/ASME B31.8 (incorporated by reference as specified in 

§ 250.198). 

(2) For limitations, see section 

841.121 of ANSI/ASME B.31.8 

(incorporated by reference as specified 

in § 250.198). When calculating the 

internal design pressure for steel pipe, 

you may account for the effects of 

external hydrostatic pressure as shown 

in ANSI/ASME B.31.8, Chapter 8 

(incorporated by reference as specified 

in § 250.198). 

(b) External design pressure. You 

must predict the external (collapse) 

design pressure for steel pipe for 

pipelines to be installed in water depths 

greater than 1000 feet using the 

equations in sections 4.3.2.1 and 4.3.2.2 

of API RP 1111 (incorporated by 

reference as specified in § 250.198). 

(c) Catenary riser for a fixed structure. 

You must design a catenary riser for a 

fixed structure according to sections 

4.5.4 and 4.1.6.2 of API RP 1111 

(incorporated by reference as specified 

in § 250.198). 

(d) Riser for tension leg platform or a 

floating system. You must design a 

pipeline riser for a tension leg platform 

or a floating system according to API RP 

2RD (incorporated by reference as 

specified in § 250.198). 

(e) Unbonded flexible pipe. If you 

plan to install a pipeline using 

unbonded flexible pipe, you must 

design the pipeline according to the 

specifications and the review standards 

for a third-party independent 

verification agent specified in API Spec 

17J (incorporated by reference as 

specified in § 250.198). 

(f) External protective coating. You 

must design a pipeline to provide the: 

(1) Horizontal component and 

appurtenances with an external 

protective coating to minimize external 

corrosion; 

(2) Risers with an additional external 

coating to resist the detrimental effects 

of corrosion, sunlight, and wave action 

in the splash zone; and 

(3) Pipe and appurtenances exposed 

to the atmosphere with a suitable 

coating. 

(g) Internal corrosion control. You 

must design a pipeline to mitigate 

internal corrosion (e.g., the use of 

internal coatings, corrosion-resistant 

alloys) over its design life. 

(h) Flow assurance. You must design 

a pipeline to ensure that adequate flow 

can be sustained throughout its design 

life (e.g., using pipe-in-pipe, insulated 

pipe, electrically heated pipe, piggable 

pipe). 

(i) Pipeline on-bottom stability. You 

must design a pipeline so that it will be 

stable in the geologic and weather 

conditions for the area. 

(1) Your pipeline must remain stable 

during a storm. The stability must be 

determined using appropriate backfill 

rates and storm data for the area. If the 

pipeline is in a water depth less than 

200 feet and is jetted at least 3 feet 

below the natural seabed, it must be 

stable during a 2-year storm (minimum). 

If you expect that the pipeline will bury 

itself naturally in the sediment in a 

water depth less than 200 feet, it must 

remain stable during a 100-year storm 

(minimum). If the pipeline is in a water 

depth 200 feet or greater and is not 

buried, it must be stable during a 100- 

year storm (minimum). 

(2) The Regional Supervisor may 

require additional stability design 

measures based on the geologic or 

weather conditions for the area. 

(j) Underwater vent pipeline. You 

must design an underwater vent 

pipeline (any pipeline that transports 

natural gas that has been vented during 

upset or abnormal conditions or bleed 


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down operations to a location where the 

gas is discharged underwater or flared at 

a flare pile) to ensure that the discharge 

point is: 

(1) A minimum of 250 feet from the 

delivering structure; and 

(2) Anchored to the sea floor, unless 

the gas is flared at a flare pile. 

(k) Riser supports. When designing 

riser supports, you must consider the: 

(1) Loads induced by riser operations; 

(2) Environmental loads, taking into 

account 100-year return period storm 

criteria as set out in API RP 2A–WSD 

(incorporated by reference as specified 

in § 250.198); and 

(3) Installation loads on risers that are 

pre-installed. 

§ 250.1034 What are the design 

requirements for appurtenances? 

You must design pipeline 

appurtenances as set forth below: 

(a) Pipeline valve. You must design a 

pipeline valve to meet the minimum 

design requirements of API Spec 6A 

(incorporated by reference as specified 

in § 250.198), API Spec 6D/ISO 14313 

(incorporated by reference as specified 

in § 250.198), or the equivalent. You 

may not use a valve under any operating 

conditions that exceed the applicable 

pressure or temperature ratings in those 

standards. The material of the valve 

must be compatible with the product 

being transported. 

(b) Pipeline flange. You must design 

a pipeline flange: 

(1) To meet the minimum design 

requirements of ANSI B16.5 

(incorporated by reference as specified 

in § 250.198), API Spec 6A 

(incorporated by reference as specified 

in § 250.198), or the equivalent; 

(2) To withstand the MAOP of the 

pipeline; 

(3) To maintain its physical and 

chemical properties at the maximum 

and minimum anticipated operating 

temperatures; and 

(4) Using material that is compatible 

with the product being transported. 

(c) Pipeline fittings. You must use 

pipeline fittings (couplings, elbows, 

unions, tees, swage nipples, buckle 

arrestors, gaskets, etc.) that: 

(1) Have pressure-temperature ratings 

based on stresses for pipe of the same 

or equivalent material; 

(2) Have a bursting strength greater 

than the computed bursting strength of 

the pipe; and 

(3) Use material that is compatible 

with the product being transported. 

(d) Anode cathodic protection system. 

You must: 

(1) Design your anode cathodic 

protection system to have a life 

expectancy of 30 years or for the design 

life of the pipeline, whichever is longer; 

and 

(2) Use the following equation, or 

another equation and/or method 

acceptable to the Regional Supervisor in 

accordance with the provisions of 

§ 250.141, to calculate anode design life: 

T MUv

I = × ×

( ) ×8760

Variable Description 

T .............. Time (years). 

M .............. Total net anode mass (pounds). 

U .............. Utilization factor. 

v ............... Electrochemical efficiency (amp 

× hour/pound). 

I ................ Current demand (amp). 

(3) You can obtain values for the 

utilization factor (U) from DNV RP 

B401, Table 6.9.1 (incorporated by 

reference as specified in § 250.198). You 

can obtain values for electrochemical 

efficiency (v) from the anode 

manufacturer. 

§ 250.1035 What are the design 

requirements for sour service? 

If your pipeline will operate in a sour 

environment (fluids containing water as 

liquid and H2S exceeding the limits 

defined in paragraphs 1.3.1.1 and 

1.3.1.2 of NACE Standard MR0175 

(incorporated by reference as specified 

in § 250.198)), you must design your 

pipeline in accordance with section 10.5 

of NACE Standard MR0175. 

§ 250.1036 When must I sectionalize a 

pipeline? 

The Regional Supervisor may require 

you to design your pipeline in sections 

to reduce the volume of your worst case 

discharge (see 30 CFR 254.47). 

Pipeline Fabrication 

§ 250.1038 What are the general 

requirements for fabricating a pipeline? 

You must fabricate each pipeline in a 

manner that: 

(a) Adheres to a suitable quality 

control program that includes 

inspection, testing, spot checks, and 

evaluation by qualified personnel; 

(b) Adheres to the specified design 

tolerances; 

(c) Conforms to recognized 

engineering practices; and 

(d) Complies with applicable 

regulations, codes, guides, standards, 

and recommended practices. 

Pipeline Construction 

§ 250.1040 What are the general 

requirements for constructing a pipeline? 

You must construct each pipeline in 

accordance with your approved 

application, and in a manner that: 

(a) Minimizes construction stresses 

and strains; 

(b) Ensures that the pipeline is 

constructed on the approved route; 

(c) Avoids or mitigates geologic and 

manmade hazards, artificial reefs, 

archaeological resources, and 

biologically sensitive features; 

(d) Minimizes the length of 

unsupported spans; and 

(e) Protects the pipeline from damage. 

§ 250.1041 Who must I notify before I 

begin construction? 

Before you begin pipeline 

construction, you must make the 

notifications in the following table: 

Who you must notify When you must make notification Other requirements 

(a) U.S. Coast Guard (USCG) ........ At least 30 calendar days before 

you conduct pipeline construction operations.

You are encouraged to notify the applicable USCG Marine Safety Office so that a Notice to Mariners can be prepared. 

(b) Military installations ................... Before you conduct pipeline construction operations in an established military warning or water 

test area.

You must notify the commander of the military installation that exercises jurisdiction of the area concerning the control of electromagnetic emissions and the use of vessels, equipment, and aircraft 

in the area. 

(c) MMS, Regional Supervisor ........ At least 48 hours before you commence construction operations.You must make this notification by telefax or email, using Form 

MMS–153 (Notification of Pipeline 

Installation/Relocation/Hydrotest). 


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§ 250.1042 What must I do to avoid or 

mitigate hazards during construction? 

To avoid or mitigate hazards during 

pipeline construction, you must comply 

with the requirements in the following 

table: 

Requirement What you must do Details 

(a) Buoying hazards ........................ Before you perform pipeline construction operations or other bottom-disturbing activities.You must: 

(1) Buoy all existing pipelines and other potential hazards located 

within 500 feet of the operation (including anchor patterns); or 

(2) In areas congested with 

pipelines or debris, use buoys to 

outline a safe working area large 

enough to accommodate your proposed pipeline construction operations..

(b) Navigation system ..................... In lieu of complying with paragraph (a) of this section.You may use a state-of-the-art, real-time primary navigational positioning equipment (e.g., DGPS) on all vessels (e.g., pipeline construction vessels, derrick barges, anchor-handling vessels) associated with your pipeline construction operations to depict existing 

pipelines and other potential hazards. 

(c) Location plat .............................. Before you perform pipeline construction operations.You must: 

(1) Prepare a plat with a minimum scale of 1:12,000 oriented to 

true north depicting the location of proposed pipeline construction operations, all associated anchor patterns, existing pipelines (both active and inactive), debris fields, or other potential hazards in the area. 

The plat must be dated, accurate, and indicative of current conditions 

(including post-hurricane conditions and recent construction or modification activities0; and 

(2) Provide copies of the plat to key personnel on all vessels (e.g., 

pipeline construction vessels, derrick barges, and anchor-handling 

vessels) associated with your pipeline construction operations. 

§ 250.1043 What must I do to install a hot 

tap? 

To install a hot tap, you must comply 

with the requirements in the following 

table: 

Requirement What you must do Details 

(a) Area inspection ............... If you plan to install a hot tap on an existing pipeline located in a water depth less than 200 feet, you must 

first determine whether proper cover is being maintained on the portion of the pipeline in the vicinity of 

the proposed work. If you determine that environmental or other factors have detrimentally affected 

the burial depth of the pipeline.

(1) Notify the Regional Supervisor within 48 hours after 

you first observe the problem; and 

(2) Submit a plan of corrective action under § 250.1097 

to the Regional Supervisor within 30 calendar days 

after you first observe the problem. 

(b) Cathodic protection system measurements.If your pipeline is located in: 

(1) The AKOCSR; or 

(2) The GOMR or POCSR, and 

(i) The pipeline is composed of any pipe that is more 

than 20 years old; or.

(ii) The life expectancy of the cathodic protection system cannot be calculated.

Take measurements of the pipe-to-electrolyte potential 

at locations along submerged sections of a pipeline 

when you conduct hot tap operations on a pipeline. 

§ 250.1044 What must I do to protect a 

horizontal component? 

To protect the horizontal component 

during construction, you must comply 

with the requirements in the following 

table: 

Component or activity Requirement 

(a) External coating ......................... You must protect the external coating of the horizontal component during construction. 

(b) Cathodic protection system ....... You must locate and install the components of the cathodic protection system in a manner that will minimize the possibility of damage. 

(c) Burial .......................................... You must bury each pipeline you install in water depths less than 200 feet to a depth of at least three feet 

below the mud line. On a case-by-case basis, the Regional Supervisor may: 

(1) Grant you approval to allow a pipeline to self bury, or allow you to use an alternative method of compliance in accordance with the provisions of § 250.141; or 


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Component or activity Requirement 

(2) Require you to increase the burial depth of a pipeline that will transport a product containing H2S in 

highly congested or active areas. 

(d) Other protective measures ........ The Regional Supervisor may require burial or other protection of the pipeline in any water depth if the Regional Supervisor determines that such measures will reduce the likelihood of environmental degradation, or mitigate a potential hazard to trawling operations or other uses of the OCS. 

(e) Burial in fairways and anchorage areas.You must consult with the U.S. Army Corps of Engineers as they may have more stringent burial requirements for pipelines that enter or cross safety fairways or anchorage areas. 

(f) Spanning .................................... You must provide sufficient supports, or use other mitigation measures (e.g., installing strakes), to avoid 

excessive loads or deformations and fatigue damage that could result from spanning. 

§ 250.1045 What must I do to protect a 

riser? 

To protect a riser during construction, 

you must comply with the requirements 

in the following table: 

You must have . . . and you must . . . 

(a) External coating ......................... Protect the external coating of the riser during construction. 

(b) Cathodic protection system ....... Locate and install the components of the cathodic protection system in a manner that will minimize the 

possibility of damage. 

(c) Vortex induced vibration (VIV) 

suppression devices.

Protect any preinstalled VIV suppression devices during construction. 

(d) Impact protection ....................... (1) Protect a pipeline riser from physical damage that could result from contact with floating vessels by 

using riser guards or other protection measures that are capable of transferring impact loads to the platform structure; and 

(2) Not use pipe-in-pipe configurations as riser impact protection. 

§ 250.1046 What must I do to protect an 

appurtenance and crossing? 

(a) Protection methods. You must 

protect all pipeline valves, taps, tie-in 

assemblies, capped pipelines, flanges, 

crossings, and repaired sections 

installed in water depths less than 500 

feet with at least 3 feet of cover or with 

a protective device (e.g., cement mats, 

cages) unless an alternate procedure is 

otherwise approved by the Regional 

Supervisor in accordance with the 

provisions of § 250.141. 

If you . . . You must . . . 

(1) Bury the appurtenance or crossing.Maintain the three-foot burial depth throughout the life of the pipeline, including after the pipeline has been 

decommissioned in place. 

(2) Use a protective device ............. Design it to be compatible with other uses of the OCS. The height and the slope of the device must allow 

for a smooth transition over the appurtenance or crossing. 

(b) Separation. You must install the 

pipeline in a manner that: 

(1) Provides for a separation of at least 

12 inches for the life of the pipeline at 

pipeline crossings, power cable 

crossings, etc.; and 

(2) Prevents physical contact with 

existing umbilicals and communication 

cables. 

(c) Existing pipelines. If you plan to 

install a pipeline that will tie into or 

cross an existing pipeline, you must 

examine the portion of the existing 

pipeline in the vicinity of the proposed 

tie-in or crossing. If you determine that 

environmental or other factors have 

detrimentally affected the burial depth 

of the pipe or any appurtenance, any 

protective cover of the pipe (in water 

depths less than 200 feet), or any 

protective cover for any appurtenance 

(in water depths less than 500 feet), you 

must notify the Regional Supervisor. 

The Regional Supervisor may require 

the responsible party to submit a plan 

of corrective action (under § 250.1097) 

to remedy the problem. 

(d) Atmospheric zone. You must 

protect valves and fittings exposed to 

the atmosphere with a suitable coating. 

§ 250.1047 What must I do to construct a 

pipeline in or near a designated use area? 

If you construct a pipeline in or near 

a designated use area, you must follow 

the requirements in the following table. 

Pipeline construction operations 

include the use of anchors, chains, and 

wire ropes. 

If your pipeline construction operations . . . Then . . . 

(a) Are conducted in or near a designated military warning or water test area.You must: 

(1) Assume all risks of damage to property, or injury to persons you employ or who are otherwise connected with your pipeline construction operations, that is caused by any act or 

omission, regardless of negligence or fault, resulting from the programs or activities of the military installation exercising jurisdiction over the military warning or water test area; 


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If your pipeline construction operations . . . Then . . . 

(2) Indemnify and hold harmless the United States against all claims for loss, damage, or injury sustained by persons you employ, or who are otherwise connected with your pipeline construction operations, that are caused by any act or omission, regardless of negligence or fault, 

resulting from the programs or activities of the military installation exercising jurisdiction over 

the military warning or water test area; 

(3) Control your electromagnetic emissions in accordance with the requirements specified by 

the commander of the military installation that has jurisdiction over the military warning or 

water test area to the degree necessary to prevent damage to, or interference with, Department of Defense flight, testing, or operations; and 

(4) Enter into an agreement with the commander of the individual command headquarters 

when you operate, or cause to be operated on your behalf, a boat, ship, or aircraft in a military 

warning or water test area. Such an agreement must provide for the positive control of boats, 

ships, and aircraft operating in the military warning or water test area at all times. 

(b) Will be in a designated lightering zone (see 

33 CFR 156.300) or traditional lightering area 

in the Gulf of Mexico.

You must contact representatives of the Industry Taskforce on Offshore Lightering to discuss 

potential conflicts between your pipeline construction operations and the lightering activities 

in these zones and areas. 

(c) Could be in a designated safety fairway or 

anchorage area, in a safety or security zone, 

or near a deepwater port.

The operations are subject to the prohibitions, restrictions, procedures, and other requirements 

contained in applicable U.S. Coast Guard regulations (see 33 CFR part 166 for fairways and 

anchorage areas, 33 CFR part 165 for safety and security zones, and 33 CFR part 150 for 

deepwater ports). 

(d) Are in the vicinity of a State-established artificial reef.You must: 

(1) Contact the appropriate State natural resource agency or artificial reef coordinator; and 

(2) Ensure that the pipeline route is not within 1000 feet, or other distance specified by the 

Regional Supervisor, from the perimeter of the artificial reef area. 

(e) Could disturb the sea floor in or near an 

area that was used until 1970 by the Department of Defense as an ordnance dumping 

area.

You must consider the area as potentially hazardous and take appropriate and necessary precautions. 

(f) Are in the vicinity of any U.S. Air Force communication towers in the Gulf of Mexico.You must ensure that: 

(1) The construction vessel and any support vessels do not move within: 

(i) A 500-foot radius of the center of a tower site; and 

(ii) 100 feet of the centerline of a line of sight between a master tower and a remote tower; 

and 

(2) Your electromagnetic transmissions do not interfere with the operation of the towers. 

§ 250.1048 What must I do to construct a 

pipeline in or near a sensitive biological 

feature or area? 

If you construct a pipeline in or near 

a biological feature or area, you must 

follow the requirements in the following 

table. Pipeline construction operations 

include the use of anchors, chains, and 

wire ropes. 

If your pipeline construction operations 

could . . . Then . . . 

(a) Disturb seafloor areas in water depths greater than 1,312 feet.You must: 

(1) If required by the Regional Supervisor, obtain appropriate high-resolution geophysical 

data of chemosynthetic communities in the area of pipeline construction operations to accurately identify and locate the features to prepare the required submittals (e.g., bathymetry map, 

survey report); 

(2) Locate all seafloor disturbances (including those caused by anchors, anchor chains, wire 

ropes, appurtenance installation, and the pipeline) at least 250 feet from any identified features 

or areas that could support high-density chemosynthetic communities; and 

(3) Use a state-of-the-art primary navigation system (e.g., DGPS) on your pipeline construction vessel and anchor-handling vessels to ensure that any seafloor disturbances do not occur 

within 250 feet of such features of areas. 

(b) Disturb the sensitive biological habitats (e.g., 

coral reefs) associated with an identified 

topographic feature.

You must: 

(1) Locate all seafloor disturbances (including those caused by anchors, anchor chains, wire 

ropes, appurtenance installation, and the pipeline) at least 500 feet outside the boundary of 

the designated ‘‘No Activity Zone’’ of such a feature; and 

(2) Use a state-of-the-art primary navigation system (e.g., DGPS) on your pipeline construction vessel and anchor-handling vessels to ensure that any seafloor disturbances do not occur 

within 500 feet of the boundary of the designated ‘‘No Activity Zone’’ of such a feature. 

(c) Disturb live bottoms (pinnacle trend features 

or seamounts) that likely provide habitat for 

high-density biological assemblages.

You must: 

(1) If required by the Regional Supervisor, obtain appropriate high-resolution geophysical 

data or photo-documentation of live bottoms (pinnacle trend features or seamounts) in the 

area of pipeline construction operations to accurately identify and locate the features and to 

prepare the required submittals (e.g., bathymetry map, survey report); 

(2) Locate all seafloor disturbances (including those caused by anchors, anchor chains, wire 

ropes, appurtenance installation, and the pipeline) at least 100 feet from the identified live bottoms; and 


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If your pipeline construction operations 

could . . . Then . . . 

(3) Use a state-of-the-art primary navigation system (e.g., DGPS) on your pipeline construction vessel and anchor-handling vessels to ensure that any seafloor disturbances do not occur 

within 100 feet of the live bottoms. 

(d) Disturb live bottoms (low relief features) that 

likely provides habitat for sea grasses; aggregated fishes, turtles, or other fauna; or coral 

community organisms.

You must: 

(1) If required by the Regional Supervisor, obtain appropriate high-resolution geophysical 

data or photo documentation of live bottoms (low relief features) in the area of operations to 

accurately identify and locate the features to prepare the required submittals (e.g., bathymetry 

map, survey report); 

(2) Locate all seafloor disturbances (including those caused by anchors, anchor chains, wire 

ropes, appurtenance installation, and the pipeline) to avoid impacting the identified live bottoms; and 

(3) Use a state-of-the-art primary navigation system (e.g., DGPS) on your pipeline construction vessel and anchor-handling vessels to ensure that you do not adversely impact the live 

bottoms. 

(e) Disturb potentially sensitive biological features, as determined from your analysis or review of survey information.You must: 

(1) Locate all seafloor disturbances (including those caused by anchors, anchor chains, wire 

ropes, appurtenance installation, and the pipeline) to avoid impacting the potentially biological 

sensitive features; and 

(2) Use a state-of-the-art primary navigation system (e.g., DGPS) on your pipeline construction vessel and anchor-handling vessels to ensure that you do not adversely impact the potentially sensitive biological features. 

(f) Adversely affect a marine sanctuary established by the Secretary of Commerce under 

the authority of section 302 of the Marine 

Protection, Research and Sanctuaries Act of 

1972, as amended (16 U.S.C. 1432).

Marine sanctuaries are subject to the prohibitions, restrictions, procedures, and other requirements contained in 15 CFR part 922. 

§ 250.1049 What must I do to construct a 

pipeline in or near an archaeological 

resource? 

If you construct a pipeline in or near 

an archaeological resource, you must 

follow the requirements in the following 

table. Pipeline construction operations 

include the use of anchors, chains, and 

wire ropes. 

If . . . You must . . . 

(a) An archaeological resource is known to exist, or the Regional Director has reason to believe that an archaeological resource may exist, 

in the area of the proposed pipeline construction operations.

Obtain appropriate high-resolution geophysical data in the area of operations to accurately identity and locate the existing or potential archaeological resources to prepare a survey report. The Regional Supervisor will specify the survey area, instrumentation, and methodology. 

(b) The review by the Regional Supervisor of the archaeological report 

included with your pipeline application (see § 250.1026(c)) concludes 

that an archaeological resource may be present.

Either: 

(1) Locate the site of your pipeline construction operations to avoid 

the potential archaeological resource by at least the distance specified 

by the Regional Supervisor; or 

(2) Establish to the satisfaction of the Regional Director that an archaeological resource either does not exist or will not be adversely affected by your pipeline construction operations. In making this determination, the Regional Director may require you to conduct further archaeological investigations, using personnel, equipment, and techniques the Regional Director considers appropriate. You must submit 

the investigation report to the Regional Director for review. 

(c) Based on further archaeological investigations, the Regional Director will notify you immediately if it’s determined that the archaeological resource exists and may be adversely affected by your pipeline construction operations.Not take any action that may adversely affect the archaeological resource until the Regional Director has told you how to protect it. 

(d) You discover a potential archaeological resource while conducting 

your pipeline surveys, pipeline construction operations, or any other 

activity related to the pipeline.

Immediately halt all seafloor disturbing operations within the area of the 

discovery and notify the Regional Director of the discovery within 72 

hours. If the site was impacted by your operations, or if impacts to 

the site or to the area cannot be avoided, the Regional Director will 

specify the additional investigations you must conduct to determine if 

the resource is potentially eligible for listing to the National Register 

of Historic Places under criteria established by 36 CFR 60.4. If these 

investigations determine that the resource is potentially eligible for 

listing in the National Register of Historic Places, the Regional Director will tell you how to protect the resource, or how to mitigate adverse impacts to the site. 


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§ 250.1050 When must I prepare and 

implement an H2S contingency plan for 

construction? 

You must prepare an H2S 

Contingency Plan before you construct a 

pipeline (using an anchor-supported 

construction vessel) that crosses a 

pipeline which transports a product 

with an H2S concentration that, if 

released, could result in atmospheric 

concentrations of 20 ppm or more. The 

H2S Contingency Plan must be in 

accordance with § 250.490(f) and cover 

your pipeline construction operations. 

You must: 

(a) Implement this H2S Contingency 

Plan before the leading construction 

vessel anchors are placed within 3,000 

feet of the crossed pipeline, and 

maintain it in effect until no trailing 

construction vessel anchors are within 

3,000 feet of the crossed pipeline; and 

(b) Keep a copy of the H2S 

Contingency Plan on the pipeline 

construction vessel. 

§ 250.1051 What information must I submit 

after construction is completed? 

(a) Construction report. You must 

submit three copies of a pipeline 

construction report to the Regional 

Supervisor within 45 calendar days after 

you complete pipeline construction. 

The construction report must include: 

(1) The MMS-assigned pipeline 

segment number. 

(2) The dates you started and 

concluded pipeline construction 

operations. 

(3) An ‘‘as built’’ location plat, based 

on NAD 27 for the GOMR (Gulf) and 

POCSR, or NAD 83 for the AKOCSR and 

GOMR (Atlantic), drawn at a minimum 

scale of 1 inch = 2,000 feet that: 

(i) Depicts the same information you 

included with your pipeline application 

(see § 250.1017(a) and (b)); 

(ii) Includes a list of the latitude and 

longitude coordinates in both NAD 27 

and NAD 83, and the X–Y coordinates 

in NAD 27 for the GOMR (Gulf) and 

POCSR, or NAD 83 for AKOCSR and 

GOMR (Atlantic), of all key points; 

(iii) Depicts the boundaries of the 

pipeline ROW, as granted, if applicable; 

and 

(iv) Includes a certification by a 

registered engineer or land surveyor that 

attests to the accuracy of the ‘‘as-built’’

locations of the pipeline and 

appurtenances. 

(4) An electronic file containing the 

digital coordinates of the key points of 

the ‘‘as-built’’ pipeline and umbilical 

routes, including turns, and, if required 

by the Regional Supervisor, the position 

of lay barge anchors, chains, and cables. 

The digital data must be in decimal 

degrees latitude and longitude and 

based on NAD 83. 

(5) Discussion of the reasons for 

deviation if the pipeline route deviates 

from the route in your approved 

application by more than 200 feet. 

(6) The type, size, weight, number, 

and spacing of any anodes that were 

installed on the pipeline, if the 

information differs substantially from 

the information you provided in your 

approved pipeline application. 

(7) A description of the protective 

covering, anchor pins, or sand bags you 

used to install or protect a valve, tap, 

subsea tie-in, capped line, or other 

appurtenance, if the installation differs 

substantially from the design you 

provided in your approved pipeline 

application. 

(8) The pipe-to-electrolyte potential 

readings for hot taps required by 

§ 250.1043(b). 

(9) A report of the hydrostatic 

pressure test (see § 250.1061) required 

by § 250.1060(a)(1). 

(10) A plat at a scale of 1 inch = 1,000 

feet (or other scale required by the 

Regional Supervisor) that depicts 

bathymetry, any biologically-sensitive 

or archaeological feature (if applicable), 

and the position of all anchors, chains, 

and cables, if the pipeline or the 

associated anchors, chains, or cables 

are: 

(i) Located in the POCSR or AKOCSR; 

or 

(ii) Located in the GOMR, and if they 

are within: 

(A) 500 feet of the ‘‘No Activity Zone’’

of an identified topographic feature or 

other biologically-sensitive feature; 

(B) 100 feet of any live bottom 

(pinnacle trend feature or seamount) 

with a vertical relief of eight feet or 

more; 

(C) 100 feet of any live bottom (low 

relief feature); or 

(D) A distance specified by the 

Regional Supervisor of any potential 

archaeological resource. 

(b) MMS actions. The Regional 

Supervisor will review your pipeline 

construction report and inform you in 

writing of any deficiencies if the report 

is unacceptable. 

(c) National Ocean Service (NOS). 

You must submit a copy of the ‘‘asbuilt’’ location plat required by 

paragraph (a)(3) of this section to the 

NOS within 45 calendar days after you 

complete pipeline construction. 

Pipeline Risers Connected To Floating 

Platforms 

§ 250.1052 What are the requirements for 

pipeline risers connected to floating 

platforms? 

(a) General. New pipeline risers and 

major modifications of, or repairs to, 

existing risers connected to floating 

platforms are subject to the Pipeline 

Riser Verification Program. A major 

modification or major repair to a 

pipeline riser means: 

(1) The replacement, removal, or 

repair of any material, component, or 

appurtenance; 

(2) Any reconfiguration or external 

event that could affect the design life of 

the riser; or 

(3) Any operation on the riser that 

involves welding. 

(b) Verification requirements. All 

pipeline risers subject to the Pipeline 

Riser Verification Program must 

undergo design verification, fabrication 

verification, and installation 

verification. 

(c) Certified Verification Agent (CVA). 

All pipeline risers subject to the 

Pipeline Riser Verification Program 

require separate verification that 

necessitates the use of a CVA 

specifically for the pipeline riser. 

(d) CVA qualifications. (1) Your 

design verification must be conducted 

by, or be under the direct supervision 

of, a registered professional civil or 

structural engineer or equivalent with 

previous experience in directing the 

design of similar risers. 

(2) Your fabrication verification must 

be conducted by qualified personnel 

with previous experience in third-party 

fabrication verification or experience in 

the fabrication of similar risers. 

(3) Your installation verification must 

be conducted by qualified personnel 

with previous experience in third-party 

installation verification or experience in 

the installation of similar risers. 

(e) CVA responsibilities. (1) The CVA 

must conduct the activities specified in 

§§ 250.1054, 250.1055, and 250.1056. 

(2) The CVA must consider the 

provisions of applicable regulations, 

codes, guides, standards, recommended 

practices, approved plans, and the 

requirements of this subpart when 

performing riser verification. 

(3) Individuals or organizations acting 

as CVA’s must not function in any 

capacity that would create a conflict of 

interest, or the appearance of a conflict 

of interest. 

(4) The CVA is the contact with the 

Regional Supervisor regarding all riser 

verification and reporting. The CVA is 

directly responsible for providing 

immediate reports to the Regional 

Supervisor of all incidents that affect 

the design, fabrication, and installation 

of pipeline risers. 

§ 250.1053 What are the requirements for 

pipeline riser verification plans? 

(a) Design verification plan. You must 

submit a design verification plan to the 

Regional Supervisor for approval before 


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the design work is completed, before 

you start fabrication and installation, 

and at least 30 calendar days before you 

submit the associated pipeline 

application. You must submit a separate 

design verification plan for each 

pipeline riser. Your design verification 

plan must include: 

(1) Riser diameter, service, type, and 

designer(s); 

(2) A project management timeline 

(Gantt Chart) that depicts key design 

activities and when the CVA will 

submit the interim and final reports 

required by § 250.1054(c) and (d); 

(3) Abstracts of the computer 

programs that will be used in design 

verification; 

(4) A summary of major design 

considerations and the approach that 

will be used to verify the validity of 

these design considerations; and 

(5) The CVA nomination information 

specified in paragraph (d) of this 

section. 

(b) Fabrication verification plan. You 

must submit a fabrication verification 

plan to the Regional Supervisor for 

approval before you start fabrication and 

at least 30 days before you submit the 

associated pipeline application. You 

must submit a separate fabrication 

verification plan for each pipeline riser. 

Your fabrication verification plan must 

include the following: 

(1) Riser diameter, service, and type; 

(2) A project management timeline 

(Gantt Chart) that depicts key 

fabrication activities and when the CVA 

will submit the interim and final reports 

required by § 250.1055(d) and (e); 

(3) A summary of major fabrication 

considerations and the approach that 

will be used to verify the validity of 

these fabrication considerations; and 

(4) The CVA nomination information 

specified in paragraph (d) of this 

section. 

(c) Installation verification plan. You 

must submit an installation verification 

plan to the Regional Supervisor at least 

30 days before you submit the 

associated pipeline application. You 

must submit a separate installation 

verification plan for each pipeline riser. 

Your installation verification plan must 

include the following: 

(1) Riser diameter, service, and type; 

(2) A project management timeline 

(Gantt Chart) that depicts key 

installation activities and when the CVA 

will submit the interim and final reports 

required by § 250.1056(d) and (e); 

(3) Abstracts of the computer 

programs that will be used in 

installation verification; 

(4) A summary of major installation 

considerations and the approach to be 

used to verify the validity of these 

installation considerations; and 

(5) The CVA nomination information 

specified in paragraph (d) of this 

section. 

(d) CVA nomination information. (1) 

As part of your design verification, 

fabrication verification, and installation 

verification plans, you must include 

nominations for your proposed CVA’s 

for the Regional Supervisor’s approval. 

(2) For each nomination, you must 

provide a qualifications statement that 

includes the following information: 

(i) Whether the nomination is for the 

design, fabrication, or installation phase 

of verification, or for any combination of 

these phases; 

(ii) Experience in the design, 

fabrication, or installation of similar 

risers; 

(iii) Experience in third-party 

verification, inspection, or auditing of 

similar risers; 

(iv) Resumes of key personnel and 

their responsibilities; 

(v) Size and type of organization or 

corporation; 

(vi) In-house availability of, or access 

to, appropriate technology, including 

computer programs, hardware, and 

testing materials and equipment; 

(vii) Ability to perform the CVA 

functions for the specific project 

considering current commitments; and 

(viii) Previous experience with MMS 

requirements and procedures. 

(e) Modifications. Submit 

modifications to your verification plans, 

including changes in the CVA and key 

personnel, to the Regional Supervisor 

for approval. 

§ 250.1054 What must the CVA do to verify 

pipeline riser design? 

The riser design CVA must use good 

engineering judgment and practices 

while conducting an independent 

verification of the design of the riser. 

The CVA must ensure that the riser is 

designed to withstand the 

environmental and functional load 

conditions appropriate for the intended 

design life of the riser at the proposed 

location. The pipeline riser design CVA 

must verify information, conduct 

analyses, and submit design reports as 

required by paragraphs (a) through (d) of 

this section. 

(a) The CVA must verify the 

following: 

(1) Planning criteria, including the 

design basis; 

(2) Operational requirements; 

(3) Environmental loading data; 

(4) Soil conditions; 

(5) Safety factors; 

(6) Material and component 

specifications; 

(7) Cathodic protection design and 

riser coating; 

(8) Interference analysis; 

(9) Input for the design of vendor 

components, such as specialty joints 

and connectors; 

(10) Vortex-induced vibration (VIV) 

suppression system to ensure that 

specifications for installation and design 

meet required suppression efficiency; 

(11) Welding specifications to ensure 

that they are appropriate and adequate 

for the design and inspection of the 

riser; 

(12) Preliminary installation analysis; 

(13) Provisions to account for marine 

growth and associated cleaning 

recommendations; 

(14) Recommendations on in-service 

inspection frequency; and 

(15) Other pertinent parameters of the 

proposed design. 

(b) The CVA must perform 

independent analyses of the following: 

(1) Riser design cases with 

appropriate load conditions, as 

specified in API RP 2RD (incorporated 

by reference as specified in § 250.198), 

including, but not limited to, operation, 

shut-in, and extreme; 

(2) Riser stresses, including extreme 

storm response for critical design 

conditions; and 

(3) Riser fatigue of selected cases that 

consider VIV, wave frequency fatigue 

analysis, vortex-induced motion (VIM), 

thermal and pressure cycles, riser 

interaction with seabed (touchdown 

zone), fatigue due to internal corrosion 

(if sour service), and other applicable 

concerns and issues. 

(c) The CVA must submit interim 

design reports to the Regional 

Supervisor at intervals approved in your 

design verification plan. The CVA must 

include the following in each interim 

design report: 

(1) Details of how, by whom, and 

when the design verification activities 

were conducted to date; 

(2) Description of the CVA’s activities 

during design verification to date; 

(3) Summary of the CVA’s findings to 

date; 

(4) Description of any outstanding or 

notable issues found on the riser design 

to date; and 

(5) A Gantt chart showing project 

progress. 

(d) The CVA must submit a final 

design report to the Regional Supervisor 

before fabrication begins and either 

within 90 calendar days after receipt of 

the design data, or within 90 calendar 

days after MMS approves the design 

verification plan, whichever is later. 

The CVA must submit a separate final 

design report for each pipeline riser. 

The CVA must include the following in 

the final design report: 


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(1) Riser diameter, service, type, and 

designer(s); 

(2) Details of how, by whom, and 

when the design verification activities; 

(3) Description of the CVA’s activities 

during design verification; 

(4) Summary of the CVA’s findings; 

(5) Confirmation of compliance with 

the design specifications; 

(6) Recommendation to accept or 

reject the riser design; and 

(7) Any additional information and 

comments that the CVA deems 

necessary including, but not limited to: 

(i) Design basis; 

(ii) Summary of design CVA scope; 

(iii) Key drawings; 

(iv) Summary of input and output 

from the independent analyses 

performed; 

(v) Comparison between results of the 

original design analyses and the CVA 

design analyses; 

(vi) In-service inspection frequency 

and inspection method 

recommendations; and 

(vii) Cleaning recommendations. 

§ 250.1055 What must the CVA do to verify 

pipeline riser fabrication? 

The riser fabrication CVA must use 

good engineering judgment and 

practices while conducting an 

independent verification of the 

fabrication activities. The CVA must 

monitor the fabrication of the riser to 

ensure that it has been built according 

to the approved design and fabrication 

plans. If the CVA finds that fabrication 

procedures are changed or design 

specifications are modified, the CVA 

must inform you. If you accept the 

modifications, then the CVA must notify 

the Regional Supervisor. The pipeline 

riser fabrication CVA must make 

inspections, witness activities, perform 

spot checks and submit fabrication 

reports as required by paragraphs (a) 

through (e) of this section. 

(a) The CVA must make periodic 

onsite inspections while fabrication is 

in progress and verify the following 

fabrication items, as appropriate: 

(1) Quality assurance and quality 

control programs; 

(2) Adequacy of fabrication site 

facilities; 

(3) Material quality and identification 

methods; 

(4) Fabrication procedures specified 

in the approved plan, and adherence to 

such procedures; 

(5) Welder and welding procedures 

qualification and identification; 

(6) Dimensional tolerances specified, 

and adherence to those tolerances; 

(7) Nondestructive examination (NDE) 

requirements, and evaluation results of 

the specific examinations; 

(8) Destructive testing requirements 

and results; 

(9) Repair procedures; 

(10) Installation of corrosion 

protection systems and splash-zone 

protection; and 

(11) Status of quality assurance and 

quality control records at various stages 

of fabrication. 

(b) The CVA must witness: 

(1) Factory Acceptance Testing (FAT) 

of vendor components; and 

(2) Welding of specialty joint to riser 

material. 

(c) The CVA must perform spot 

checks as necessary to determine 

compliance with applicable regulations, 

codes, guides, standards, recommended 

practices, and approved plans. 

(d) The CVA must submit interim 

fabrication reports to the Regional 

Supervisor at intervals approved in your 

verification plan. The CVA must 

include the following in each interim 

fabrication report: 

(1) Details of how, by whom, when, 

and where the fabrication verification 

activities were conducted to date; 

(2) Description of the CVA’s activities 

during fabrication verification to date; 

(3) Summary of the CVA’s findings to 

date; 

(4) Description of any outstanding or 

notable riser design issues found to 

date; and 

(5) A Gantt chart showing project 

progress. 

(e) The CVA must submit a final 

fabrication report to the Regional 

Supervisor within 90 calendar days after 

completion fabrication, but before the 

beginning of pipeline installation. The 

CVA must submit a separate final 

fabrication report for each pipeline riser. 

The CVA must include the following in 

the final fabrication report; 

(1) Riser diameter, service, and type; 

(2) Details of how, by whom, when, 

and where the fabrication verification 

activities were conducted; 

(3) A description of the CVA’s 

activities during fabrication verification; 

(4) A summary of the CVA’s findings; 

(5) Confirmation of compliance with 

the design specifications and the 

approved fabrication plan; 

(6) Recommendations to accept or 

reject the fabrication; and 

(7) Any additional information and 

comments that the CVA deems 

necessary, including: 

(i) Summary of fabrication scope; 

(ii) Welding program details; 

(iii) NDE program details, including 

acceptance criteria and evaluation 

results; 

(i) Dimensional control adherence; 

(v) The inspection report of the FAT 

of vendor components; and 

(vi) Quality assurance and quality 

control program details. 

§ 250.1056 What must the CVA do to verify 

pipeline riser installation? 

The pipeline riser CVA must use good 

engineering judgment and practice in 

conducting an independent verification 

of the installation activities. The CVA 

must monitor the installation of the riser 

to ensure that it has been built 

according to the approved design and 

installation plans. If the CVA finds that 

installation procedures are changed or 

design specifications are modified, the 

CVA must inform you. If you accept the 

modifications, the CVA must notify the 

Regional Supervisor. The pipeline riser 

installation CVA must verify 

compliance, perform spot checks, and 

submit fabrication reports as required by 

paragraphs (a) through (e) of this 

section. 

(a) The CVA must verify the: 

(1) Quality assurance and quality 

control program; 

(2) Adequacy of installation vessel(s) 

and equipment; 

(3) Material quality and identification 

methods; 

(4) Installation procedures specified 

in the approved installation plan, and 

adherence to such procedures; 

(5) Welder and welding procedures 

qualification and identification; 

(6) Dimensional tolerances specified, 

and adherence to those tolerances; 

(7) NDE requirements, and evaluation 

results of the specified examinations; 

(8) Repair procedures; 

(9) Installation test data; 

(10) Installation of corrosion 

protection systems and splash-zone 

protection; 

(11) Installation of VIV suppression 

devices as specified in the approved 

design, and adherence to such design; 

and 

(12) Status of quality assurance and 

quality control records at various stages 

of installation. 

(b) The CVA must perform spot 

checks as necessary to determine 

compliance with applicable regulations, 

codes, guides, standards, recommended 

practices, and approved plans. 

(c) The CVA must witness the: 

(1) Pipe load-out at the shore base; 

and 

(2) Riser installation operations. 

(d) The CVA must submit interim 

installation reports to the Regional 

Supervisor at intervals approved in your 

verification plan. The CVA must 

include the following in each interim 

installation report: 

(1) Details of how, by whom, when, 

and where the installation verification 

activities were conducted to date; 


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(2) Description of the CVA’s activities 

during installation verification to date; 

(3) Summary of the CVA’s findings to 

date; 

(4) Description of any outstanding or 

notable riser design issues found to 

date; and 

(5) A Gantt chart showing project 

progress. 

(e) The CVA must submit a final 

installation report to the Regional 

Supervisor within 45 calendar days after 

installation of the pipeline. The CVA 

must submit a separate installation 

report for each pipeline riser. The CVA 

must include the following in the final 

installation report: 

(1) Riser diameter, service, and type; 

(2) Details of how, by whom, when, 

and where the installation verification 

activities were conducted; 

(3) A description of the CVA’s 

activities during installation 

verification; 

(4) Summary of the CVA’s findings; 

(5) Confirmation of compliance with 

the design specifications and the 

approved installation plan; 

(6) A recommendation to accept or 

reject the installation; and 

(7) Any additional information and 

comments that the CVA deems 

necessary, including: 

(i) Summary of installation scope; 

(ii) Welding program details, 

including weld maps; 

(iii) NDE program details, including 

acceptance criteria and evaluation 

results; 

(iv) Dimensional control adherence; 

(v) Quality assurance and quality 

control program details; 

(vi) Incidents that occurred during 

installation; and 

(vii) As-built drawings. 

Pipeline Pressure Testing 

§ 250.1057 What are the general 

requirements for pressure testing a 

pipeline? 

You must pressure test a pipeline in 

a manner that: 

(a) Verifies that the pipeline has the 

requisite structural integrity to 

withstand normal and maximum 

operating pressures, and is capable of 

product containment; 

(b) Ensures that the test equipment is 

properly selected and in good working 

order; and 

(c) Uses work practices and 

procedures that reduce hazards to 

personnel and equipment, and protect 

the environment. 

§ 250.1058 What are the requirements for 

conducting a hydrostatic pressure test for 

a pipeline? 

(a) Purpose. A hydrostatic pressure 

test must test the tensile strength of a 

pipeline by pressuring up the pipeline 

with water. 

(b) Notification. You must notify the 

Regional Supervisor, using Form MMS–

153 (Notification of Pipeline 

Installation/Relocation/Hydrotest), at 

least 48 hours before you conduct a 

hydrostatic pressure test on a pipeline. 

(c) Equipment. During a hydrostatic 

pressure test, you must: 

(1) Measure the test fluid temperature 

and the test fluid pressure using 

synchronized temperature and pressure 

recorders; and 

(2) Use pressure gauges and recorders 

that are sufficiently accurate to 

determine whether the pipeline is 

leaking during the test. 

(d) Procedures. When you conduct a 

hydrostatic pressure test, you must: 

(1) Test the pipeline (including the 

riser(s)) at a minimum stabilized 

pressure of at least 125 percent of the 

MAOP for the length of time specified 

in § 250.1060(a), (b), or (c); 

(2) Take deadweight test readings and 

record the reading, time, and reason for 

any pressure fluctuations at intervals no 

greater than 30 minutes; and 

(3) Use a test pressure that will not 

produce a stress in the pipeline in 

excess of 95 percent of the specified 

minimum-yield strength of the pipe. 

(e) Successful test. A successful 

hydrostatic pressure test means that 

there was no observable leakage, and a 

stabilized pressure was maintained for 

the last 2 hours of the test. 

(f) Discharging test medium. You 

must dispose of the test medium in 

accordance with applicable laws and 

regulations. 

§ 250.1059 What are the requirements for 

leak testing a pipeline? 

(a) Conducting a leak test. When you 

conduct a leak test, you must: 

(1) Use a stabilized pressure that is 

capable of detecting all leaks; 

(2) Use pressure gauges and recorders 

that are sufficiently accurate to 

determine whether the pipeline is 

leaking during the test; and 

(3) Conduct the test for at least two 

hours during daylight. 

(b) Successful leak test. A leak test 

must successfully test the integrity of a 

pipeline. A successful leak test means 

no observable leakage during the test 

period. 

§ 250.1060 When must I perform a 

pressure test on a pipeline? 

(a) Hydrostatic pressure test. After 

you install the pipeline, you must 

successfully perform an 8-hour 

hydrostatic pressure test of a pipeline 

(including the riser(s)) before you: 

(1) Put a new pipeline into service; 

(2) Put a relocated pipeline into 

service; 

(3) Put a pipeline with an increased 

MAOP into service; 

(4) Reactivate a pipeline that was out 

of service for more than one year; 

(5) Re-commission a pipeline that was 

decommissioned; or 

(6) Re-activate a pipeline that was 

modified by adding new pipe (except in 

the case of a pipeline repair using a 

spool piece that complies with 

paragraph (c) of this section). 

(b) Pressure test after repair using a 

clamp. Before you return a pipeline to 

service following a repair using a clamp: 

If you completed the repair using a . . . You must successfully perform . . . 

(1) Mechanical clamp ......................................... A leak-test of the pipeline (including riser(s)) or, if required by the Regional Supervisor, an 8- 

hour hydrostatic pressure test of the pipeline (including riser(s)). 

(2) Welded clamp ............................................... An 8-hour hydrostatic pressure test of the pipeline (including riser(s)). 

(c) Pressure test after repair using a 

spool piece. Before you return a pipeline 

to service following a repair using a 

spool piece you must meet the 

requirements in the following table: 

After you install the spool piece, if . . . You must successfully perform . . . 

(1) You connected the spool piece using 

flanges.

A 4-hour hydrostatic pressure bench test of the spool piece, and a leak test of the pipeline (including riser(s)). 


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After you install the spool piece, if . . . You must successfully perform . . . 

(2) The spool piece is visible during the test 

and is not connected using flanges.

A 4-hour hydrostatic pressure test of the pipeline (including riser(s)), and a non-destructive test 

(i.e., x-rays) of the connections. 

(3) The spool piece is not visible during the test An 8-hour hydrostatic pressure test of the pipeline (including riser(s)). 

(d) Directed pressure test. The 

Regional Supervisor may require you to 

pressure test a pipeline to verify its 

integrity whenever the Regional 

Supervisor determines that there is a 

reasonable likelihood that the pipeline 

was damaged or weakened by external 

or internal conditions. When so 

directed, you must submit the results of 

these tests to the Regional Supervisor 

(see § 250.1061). 

§ 250.1061 What information must I 

include in a pressure test report? 

(a) Hydrostatic pressure test. You 

must submit the results of the 

hydrostatic pressure test in conjunction 

with the reports required by 

§§ 250.1051(a)(9), 250.1060(d), 

250.1086(g)(5), 250.1093(g)(5), 

250.1095(e)(6), and 250.1113(b)(5). The 

pressure test report must include: 

(1) Test description; 

(2) Pressure and temperature charts; 

(3) Instrument calibration data; 

(4) Minimum and maximum pressure 

calculations; 

(5) Deadweight pressure test readings 

and temperature log; 

(6) Record of problems encountered 

during the test including their causes 

and corrective actions taken; and 

(7) Documentation of any factors that 

affected pressures or temperatures. 

(b) Leak test. You must submit the 

pressure and temperature charts of any 

required leak test in conjunction with 

the report required by § 250.1095(e)(7). 

Pipeline Safety Equipment 

§ 250.1062 What are the general 

requirements for pipeline safety 

equipment? 

You must provide each pipeline with 

safety equipment that: 

(a) Prevents or minimizes the 

consequences of overpressure, leaks, 

and failures; 

(b) Protects personnel and the 

environment; 

(c) Considers the need to limit surge 

pressures and other deviations from 

normal operations; and 

(d) Is properly installed, operated, and 

maintained. 

§ 250.1063 What are the safety equipment 

requirements for a departing pipeline? 

(a) Departing pipeline means a 

pipeline that receives: 

(1) Production from a production, 

boosting, compressor, or manifold 

platform; a subsea well, manifold, or 

other facility; or an incoming pipeline; 

(2) Gas-lift gas; 

(3) Supply gas; or 

(4) Water, fuel, or chemicals. 

(b) You must comply with the safety 

requirements for a departing pipeline in 

the following table: 

Safety equipment Requirements 

(1) Pressure safety high and 

low (PSHL) sensors.

You must protect a departing pipeline with PSHL sensors that directly or indirectly shut in all delivering sources. 

(2) PSHL sensor settings ..... (i) You must set the PSHL sensors required by paragraph (a) of this section to activate at pressures that are no 

more than 15 percent above and below the limits of the normal operating pressure range of the pipeline. 

(ii) For pipelines that transport a product containing H2S, you must set the pressure safety low (PSL) sensor to 

activate at a pressure that is no more than 10 percent below the lower limit of the normal operating pressure 

range of the pipeline. 

(iii) For a departing pipeline that receives production from a subsea well, you may set the pressure safety high 

(PSH) sensor to activate at a pressure that is up to 5 percent above the latest recorded wellhead shut-in tubing 

pressure. 

(iv) You must not set the PSH sensor to activate at a pressure greater than the MAOP of the pipeline. 

(v) You must not set the PSH sensor to activate at a pressure within 5 percent of the pressure safety valve (PSV) 

set point. 

(3) PSHL sensor settings determination.(i) You must determine the sensor settings required by paragraph (b) of this section by using a pressure recorder 

to establish the current normal operating pressure range. You must keep the most current pressure recorder 

charts at the nearest OCS facility, and make them available for inspection by MMS upon request. 

(ii) For a departing pipeline that receives production from a subsea well, you must use well test records to determine the sensor settings. You must keep the most recent well test records at the nearest OCS facility, and 

make them available for inspection by MMS upon request. 

(4) Flow safety valve (FSV) 

and shutdown valve (SDV).

The Regional Supervisor may require you to equip or otherwise protect a departing pipeline with an FSV and/or 

an automatic SDV. 

(5) Subsea tie-in ................... You must equip the originating end of all departing pipelines that receive production from a connecting pipeline at 

a subsea tie-in with a block valve and an FSV. 

§ 250.1064 What are the safety equipment 

requirements for an incoming pipeline? 

(a) Incoming pipeline means a 

pipeline that delivers: 

(1) Production to a production, 

booster, or compressor platform; 

(2) Gas-lift gas to a well, manifold 

platform, or to another pipeline at a 

subsea tie-in; 

(3) Supply gas; or 

(4) Water, fuel, or chemicals. 

(b) You must comply with the safety 

equipment requirements for an 

incoming pipeline in the following 

table: 

Safety equipment Requirements 

(1) FSV ................................. You must protect an incoming pipeline with an FSV to prevent backflow. 


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Safety equipment Requirements 

(2) SDV ................................ You must equip an incoming pipeline, except a water pipeline, that boards a production platform or manned platform (a platform that has personnel on board 24 hours per day, or on which personnel are quartered overnight) 

with an automatic SDV that: 

(i) Is actuated by the platform’s automatic- and remote-emergency shut-in systems; 

(ii) Is located immediately upon boarding the platform. If the SDV is on a horizontal section, you must locate it in 

an unclassified area (classified area is defined in API RP 500 and API RP 505; both documents are incorporated by reference in § 250.198) and no more than 10 feet from the boarding pipeline riser. This requirement 

applies only to pipelines installed or modified after [INSERT THE EFFECTIVE DATE OF THE RULE]; and 

(iii) Closes within 45 seconds after it is actuated. 

(3) Gas-lift pipeline ............... This paragraph applies to an existing incoming gas-lift pipeline installed before [INSERT THE DATE SIX 

MONTHS AFTER THE EFFECTIVE DATE OF THE RULE] to an unmanned minor platform. (A minor platform 

is one that contains fewer than six well completions or fewer than two pieces of production equipment). In lieu 

of complying with paragraphs (b)(1) and (b)(2) of this section, you may protect the pipeline with an FSV located 

either: 

(i) Immediately upstream of each casing annulus; or 

(ii) Immediately upstream of the first inlet valve on the wellhead. 

(4) Subsea tie-in ................... You must equip the terminating end of an incoming pipeline that delivers production to a connecting pipeline at a 

subsea tie-in with a block valve and an FSV. 

§ 250.1065 What are the safety equipment 

requirements for a crossing pipeline? 

(a) A crossing pipeline means a 

pipeline that crosses a platform but does 

not receive or deliver production to that 

platform. A crossing pipeline includes 

both the incoming and departing 

pipeline segments. 

(b) You must comply with the safety 

requirements for a crossing pipeline in 

the following table: 

Safety equipment Requirements 

(1) FSV ................................. You must protect a crossing pipeline installed after [INSERT THE EFFECTIVE DATE OF THE RULE] that 

crosses an unmanned or non-production platform with an FSV to prevent backflow. 

(2) SDV ................................ You must equip the terminating end of the incoming segment(s) of a crossing pipeline (except a water pipeline) 

that crosses a production platform or manned platform (a platform that has personnel on board 24 hours per 

day, or on which personnel are quartered overnight) with an automatic SDV that: 

(i) Is operated by a PSHL sensor to protect the departing segment(s) of the crossing pipeline; 

(ii) Is actuated by the platform’s automatic- and remote-emergency shut-in systems; 

(iii) Is located immediately upon boarding the platform. If the SDV is on a horizontal section, you must locate it in 

an unclassified area (a classified area is defined in API RP 500 and API RP 505; both documents are incorporated by reference in § 250.198) and no more than 10 feet from the boarding pipeline riser. This requirement 

applies only to pipelines installed or modified after [INSERT THE EFFECTIVE DATE OF THE RULE]; and 

(iv) Closes within 45 seconds after it is actuated. 

§ 250.1066 What are the safety equipment 

requirements for a bi-directional pipeline? 

(a) Bidirectional pipeline means a 

pipeline designed and configured to 

transport fluids in either direction. 

(b) You must comply with the safety 

equipment requirements for a bidirectional pipeline in the following 

table: 

Safety equipment Requirements 

(1) PSHL sensors ................. You must protect both ends of a bi-directional pipeline with PSHL sensors that directly or indirectly shut in all delivering sources. Requirements for the setting levels of the PSHL sensors are specified at §§ 250.1063(b)(2) 

and (3). 

(2) Automatic SDV ............... You must equip both ends of a bi-directional pipeline with an automatic SDV that: 

(i) Is actuated by the platform’s automatic- and remote-emergency shut-in systems; 

(ii) Is located immediately upon boarding the platform. If the SDV is on a horizontal section, you must locate it in 

an unclassified area (a classified area is defined in API RP 500 and API RP 505, both documents incorporated 

by reference as specified in § 250.198) and no more than 10 feet from the boarding pipeline riser. This requirement applies only to pipelines installed or modified after [INSERT THE EFFECTIVE DATE OF THE RULE]; and 

(iii) Closes within 45 seconds after it is actuated. 

(3) Block valve ..................... You must equip a bi-directional pipeline that connects to a pipeline at a subsea tie-in with a block valve at the tiein assembly. 

§ 250.1067 When must I provide redundant 

safety equipment? 

(a) If the maximum source pressure 

(MSP) is from a well, and it exceeds the 

MAOP of the pipeline, you must protect 

the pipeline by using either: 

(1) One surface safety valve (SSV) 

controlled by a PSH sensor, and a PSV 

that relieves in a safe and pollution-free 

manner; or 

(2) Two SSV’s controlled by 

independent PSH sensors connected to 

separate relays and sensing points. 

(b) For pipelines installed after 

[INSERT THE EFFECTIVE DATE OF 

THE RULE], if the MSP is from a well, 

and it is more than 11⁄2 times the MAOP 

of the pipeline, you must protect the 

pipeline by using two SSV’s controlled 

by independent PSH sensors connected 


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to separate relays and sensing points, 

and one PSV that relieves in a safe and 

pollution-free manner. 

(c) If the maximum source pressure 

(MSP) is not from a well, and it exceeds 

the MAOP of the pipeline, you must 

protect the pipeline by using either: 

(1) One shutdown valve (SDV) 

controlled by a PSH sensor, and a PSV 

that relieves in a safe and pollution-free 

manner; or 

(2) Two SDV’s controlled by 

independent PSH sensors connected to 

separate relays and sensing points. 

(d) If you use the configuration 

specified in paragraph (c)(1) above, you 

must set the PSV to activate at a 

pressure between 5 and 10 percent 

above the MAOP. 

§ 250.1068 What are the safety equipment 

requirements for a pipeline pump? 

(a) General. You must do both of the 

following: 

(1) Protect a pipeline pump according 

to section A7 of API RP 14C 

(incorporated by reference as specified 

in § 250.198). Requirements for setting 

the levels of the PSHL sensors are 

specified at § 250.1063(b)(2) and (3). 

(2) Set any PSV you installed on the 

pipeline to protect the pump to activate 

at a pressure less than the MAOP of the 

pipeline. 

(b) Time delays for pumps. During 

startup and idle operations, you may 

apply industry standard Class B, Class 

C, and Class B/C logic to all PSL sensors 

installed on pipeline pumps. You do not 

need a departure approval to use these 

types of time delay circuitry if the time 

delay does not exceed 45 seconds. You 

must obtain a departure approval under 

the provisions of § 250.142 from the 

appropriate District Manager before you 

use a time delay greater than 45 

seconds. 

(1) Class B logic allows for a PSL 

sensor on pipeline pumps to be 

bypassed for a fixed time period 

(typically less than 15 seconds, but not 

more than 45 seconds). 

(2) Class C logic allows for a PSL 

sensor to be bypassed until the 

component comes into full service. 

(3) Class B/C logic allows for a PSL 

sensor to incorporate a combination of 

Class B and Class C circuitry. This 

device is used to ensure that a PSL 

sensor is not unnecessarily bypassed 

during start-up and idle operations (e.g., 

Class B/C bypass circuitry activates 

when a pump is shut down during 

normal operations). The PSL sensor 

remains bypassed until the pump start 

circuitry is activated and either: 

(i) The Class B timer expires after 45 

seconds from start activation; or 

(ii) The Class C bypass is initiated 

until the pump builds up pressure 

above the PSL set point and the PSL 

comes into full service. 

(c) PSL Sensors and bypass circuits. 

When the PSL sensor comes into full 

service, the PSL sensor is fully active. If 

the PSL sensor should trip while the 

pump is running, the pump will shut 

down and the Class B/C bypass circuit 

will remain inactive until the safety 

system devices are cleared and reset. 

§ 250.1069 What must I do if safety 

equipment fails to operate as intended? 

If any safety equipment required by 

this subpart experiences a failure you 

must follow the requirements of 

paragraphs (a) through (e) of this 

section. 

(a) Suspending operations. You must 

shut in the pipeline immediately. 

(b) Out-of-service notification. You 

must notify the Regional Supervisor: 

(1) If the safety equipment remains 

out of service for more than 12 hours in 

the GOMR; and 

(2) Immediately after the safety 

equipment is out of service in the 

POCSR and AKOCSR. 

(c) Resuming operations. You may 

resume operation of the pipeline after 

you: 

(1) Repair the failed safety equipment 

(see §§ 250.1094 through 1096); 

(2) Replace the failed safety 

equipment (see § 250.1093); or 

(3) Provide an equivalent degree of 

protection and place an appropriate 

warning sign on the failed safety 

equipment. 

(d) Corrective action notification. If 

you shut in your pipeline because of a 

safety equipment failure and were 

required by paragraph (b) of this section 

to notify the Regional Supervisor, you 

must also notify the Regional Supervisor 

immediately when you repair the safety 

equipment and resume operating the 

pipeline, or when you have provided an 

equivalent degree of protection and 

resume operating the pipeline. 

(e) Repair application. If the 

corrective action you take to address a 

safety equipment failure necessitates a 

repair (see § 250.1094), you must submit 

a repair application in accordance with 

§ 250.1095(a) and receive approval from 

the Regional Supervisor before you 

perform the work. 

Pipeline Leak Detection 

§ 250.1071 When do I need to use a leak 

detection system? 

If your pipeline transports liquid 

hydrocarbons to shore, or if the Regional 

Supervisor otherwise requires it, you 

must use a computational pipeline 

monitoring (CPM) system or equivalent 

methodology to detect leaks by 

continuously determining or calculating 

the imbalance between the incoming 

(receipt) and outgoing (delivery) 

volumes of a pipeline. A CPM system 

means an algorithmic monitoring tool 

that allows you to respond to a pipeline 

operating anomaly that may indicate a 

release of liquid hydrocarbons. You 

must: 

(a) Equip your CPM system with an 

alarm that signals when the imbalance 

exceeds a predetermined threshold for a 

selected time interval; and 

(b) Use SCADA technology to gather, 

process, and display the data you use in 

your CPM system. SCADA is an 

acronym for supervisory control and 

data acquisition, the technology that 

makes it possible to monitor and control 

pipelines remotely. 

Pipeline Internal Corrosion Control and 

Flow Assurance 

§ 250.1074 What are the general 

requirements for internal corrosion control? 

You must establish and implement 

internal corrosion control measures 

(e.g., running pipeline scrapers; 

dehydrating; using corrosion inhibitors, 

bactericides, or oxygen scavengers) to 

protect the pipeline over its service life. 

§ 250.1075 What are the general 

requirements for flow assurance? 

You must establish and implement 

measures (e.g., chemical additives, 

routine pigging) to ensure that adequate 

flow can be sustained throughout the 

service life of a pipeline under all 

expected flow conditions for the range 

of pressures, temperatures, fluid 

properties, and phase conditions 

expected during start up, normal, shut 

down, and emergency operations. 

Pipeline Operations and Maintenance 

§ 250.1078 What are the general 

requirements for operating and maintaining 

a pipeline? 

You must operate and maintain a 

pipeline in a manner that: 

(a) Protects life, property, and the 

environment for the service life of the 

pipeline; 

(b) Ensures that all pipelines, 

appurtenances, and safety equipment 

are not subjected to operating 

conditions that exceed applicable 

design parameters and the MAOP; 

(c) Anticipates the detrimental effects 

of corrosion; product composition; 

thermal cycling; pressure fluctuations; 

hydrate, asphaltene, or paraffin 

formation; sediment transfer or scour 

(due to wave action and currents); storm 

or ice scouring; gross seafloor movement 

(such as mudslides, faults, and 

subsidence); hurricanes; earthquakes; 

subfreezing temperatures; and other 

natural or manmade phenomena; 


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(d) Maintains the approved burial 

depth throughout the life of the pipeline 

including after the pipeline is 

decommissioned in place; and 

(e) Does not interfere with other uses 

of the OCS. 

§ 250.1079 What written procedures must I 

establish before I operate an OCS pipeline? 

(a) Operations and maintenance 

manual. You must prepare a written 

operations and maintenance manual for 

your OCS pipelines that complies with 

the regulations in this subpart and 

includes provisions for all of the 

following: 

(1) Conducting normal operations; 

(2) Conducting periodic surveillance 

and inspections; 

(3) Performing systematic and routine 

preventive maintenance; 

(4) Ensuring that safety system 

components are functioning properly; 

(5) Resuming operations after a storm; 

(6) Monitoring and mitigating the 

effects of internal and external corrosion 

and erosion; 

(7) Monitoring and mitigating the 

effects of paraffin, wax, and hydrate 

formation; 

(8) Responding to foreseeable 

abnormal operating conditions, 

malfunctions, failures, or personnel 

error; and 

(9) Identifying and responding to 

conditions that could affect safe 

operations. 

(b) Integrity management program. 

You must have a written pipeline 

integrity management program for your 

OCS pipelines that includes the seven 

elements listed in this paragraph. 

(1) Baseline integrity assessment. A 

plan and a risk-based schedule for 

obtaining baseline information on the 

integrity of each pipeline by either: 

(i) Using an in-line inspection tool 

(e.g., smart pig) to detect corrosion or 

deformation anomalies; 

(ii) Performing hydrostatic pressure 

tests (see § 250.1058) to test tensile 

strength; or 

(iii) Using other technology that can 

provide an equivalent understanding of 

the condition of your pipelines. 

(2) Information analysis. An analysis 

that integrates all other available 

information (e.g., inspections, tests, 

surveys, and monitoring results) about 

pipeline integrity. 

(3) Review. Provisions to review the 

integrity assessment results and 

information analysis by a qualified 

person. 

(4) Remedial actions. Criteria for 

performing prompt remedial actions to 

address anomalous conditions you 

discover through integrity assessment or 

information analysis. 

(5) Periodic assessment and 

evaluation. Provisions for periodically 

reassessing and re-evaluating the 

integrity of the pipeline at a frequency 

based on specific risk factors such as 

proximity to environmentally sensitive 

areas, product being transported, 

previous failure history, and water 

depth. 

(6) Preventive and mitigation 

measures. Provisions for identifying and 

taking preventive and mitigation 

measures to enhance safety and 

environmental protection such as 

SCADA systems, cathodic protection 

monitoring, and shorter inspection 

intervals. 

(7) Program effectiveness. Provisions 

for measuring the effectiveness of your 

integrity management program. 

(c) Emergency plan. You must prepare 

a written emergency plan that you will 

immediately implement in the event of 

a pipeline failure, accident, or other 

emergency that includes provisions for: 

(1) Training personnel responsible for 

executing emergency actions; 

(2) Establishing an effective 

communication system; 

(3) Conducting periodic drills; 

(4) Ensuring personnel safety; 

(5) Evacuating platforms; 

(6) Limiting property damage; 

(7) Minimizing pollution and 

protecting the environment; 

(8) Conducting remote operations, if 

applicable; 

(9) Making construction information 

and operating history available to 

appropriate personnel; 

(10) Notifying appropriate 

government agencies; 

(11) Investigating failures; and 

(12) Reviewing performance during 

drills and actual emergencies. 

(d) Personnel qualification program. 

You must have a written qualification 

program for individuals who perform 

pipeline operation, maintenance, and 

repair duties for you that may affect the 

safe operation or integrity of a pipeline. 

This program must include provisions 

for: 

(1) Identifying covered tasks; 

(2) Ensuring through periodic 

evaluation that the individuals who 

perform covered tasks are qualified; 

(3) Evaluating an individual if you 

have reason to believe that the 

individual’s performance of a covered 

task contributed to an incident; 

(4) Evaluating an individual if you 

have reason to believe that the 

individual is no longer qualified to 

perform a covered task; 

(5) Communicating changes that affect 

covered tasks to individuals performing 

those tasks; and 

(6) Complying with 30 CFR 250, 

Subpart O—Well Control and 

Production Safety Training, as 

applicable. 

(e) Implementation procedures. You 

must establish procedures to make sure 

that your personnel implement and 

follow the provisions of your operations 

and maintenance manual, integrity 

management program, emergency plan, 

and personnel qualification program. 

(f) Annual review. You must review 

your operations and maintenance 

manual, integrity management program, 

emergency plan, and personnel 

qualification program at least annually 

and make any necessary changes to 

ensure that they remain effective. 

(g) Inspection. You must make copies 

of your operations and maintenance 

manual, integrity management program, 

emergency plan, and personnel 

qualification program available to MMS 

personnel at the nearest OCS facility 

upon request. 

§ 250.1080 When must I mark the MMSassigned pipeline segment number on a 

pipeline? 

You must comply with the marking 

requirements indicated in the following 

table: 

Type of pipeline When you must mark the pipeline segment number 

(a) New pipeline ................... Before you operate a pipeline you construct after [INSERT THE EFFECTIVE DATE OF THE REGULATION], you 

must durably mark the MMS-assigned pipeline segment number on the pipeline at each platform. 

(b) Existing pipeline .............. If you constructed a pipeline before [INSERT THE EFFECTIVE DATE OF THE REGULATION], you must durably 

mark the MMS-assigned pipeline segment number on the pipeline at each platform no later than [INSERT THE 

DATE 6 MONTHS AFTER THE EFFECTIVE DATE OF THE REGULATION]. 


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Type of pipeline When you must mark the pipeline segment number 

(c) Exception ........................ You are not required to separately mark the MMS-assigned pipeline segment number on a pipeline to comply 

with paragraphs (a) or (b) of this section if you durably mark the component identification (see API RP14C, 

section 2.4 (incorporated by reference as specified in § 250.198)) on the pipeline using the MMS-assigned 

pipeline segment number as the unique identifier (e.g., KAH–1425, where 1425 is the MMS-assigned pipeline 

segment number). 

§ 250.1081 How do I determine the MAOP 

of a pipeline? 

The MAOP of a pipeline must not 

exceed the lowest of the following: 

(a) The internal design pressure of the 

horizontal component and risers; 

(b) The pressure ratings of 

appurtenances; 

(c) Eighty percent of the hydrostatic 

test pressure of the pipeline; or 

(d) If applicable, the MAOP of a 

connecting pipeline. 

§ 250.1082 What must I do if the pipeline 

transports H2S? 

(a) H2S Contingency Plan for 

operations. Before you operate a 

pipeline which transports a product 

with an H2S concentration that, if 

released, could result in atmospheric 

concentrations of 20 ppm or more, you 

must prepare an H2S Contingency Plan 

in accordance with § 250.490(f) that 

covers your pipeline operations. You do 

not need to prepare an H2S Contingency 

Plan if the pipeline is covered under an 

appropriate facility plan. 

(b) H2S dispersion modeling report. 

Before you operate a pipeline which 

transports a product with an H2S 

concentration greater than 500 ppm, you 

must model a potential worst-case 

accidental H2S release from the pipeline 

and prepare a report. The modeling 

report must include: 

(1) The data you used in the model 

(e.g., meteorological data) in an 

electronic format acceptable to the 

Regional Supervisor; 

(2) A site-specific analysis of your 

pipeline operation that considers any 

nearby human-occupied OCS platforms, 

shipping lanes, fishery areas, and other 

points where humans may be subject to 

potential exposure from an accidental 

H2S release; and 

(3) If the accidental release could 

result in an H2S concentration of 10 

ppm or greater at an onshore area, an 

analysis consistent with the risk 

management plan (RMP) methodologies 

of the EPA as outlined in 40 CFR part 

68. 

(c) Batch treatment. The Regional 

Supervisor may require that you batch 

treat your pipeline if there are 

indications that H2S could be 

detrimentally affecting the pipeline. 

§ 250.1083 What are the requirements for 

conducting remote operations during a 

platform evacuation? 

(a) Pipeline shut-in. When you 

evacuate your personnel from an OCS 

platform due to an impending storm or 

other emergency, you must shut in any 

connecting pipeline unless you have 

remote operations capability. 

(b) Remote operations. You may 

conduct remote operations on the 

pipeline during an evacuation only if: 

(1) The Regional Supervisor grants 

you prior approval; 

(2) Your pipeline has remote 

monitoring and remote shut-in 

capabilities; 

(3) You immediately shut in any 

pipeline that transports liquid 

hydrocarbons or H2S, or any pipeline 

that transports natural gas (if the 

pipeline experiences an upset 

condition) when the sustained wind 

speeds of any storm reach 74 mph over 

any part of the pipeline; and 

(4) You design time-delay circuitry 

(local storm timers) to shut in a pipeline 

no more than 4 hours after the 

capability to monitor and control a 

process is lost, and include this 

circuitry in the SCADA logic. 

(c) Resuming operations. You may not 

remotely resume operation of a shut-in 

pipeline if any part of the pipeline was 

within 25 miles (or other distance 

specified by the Regional Supervisor) of 

the eye center path of a major storm (74 

mph or greater). 

§ 250.1084 What are the requirements for 

testing pipeline safety equipment? 

(a) You must periodically test your 

pipeline safety equipment to ensure that 

it is in good mechanical condition, 

properly installed, and able to perform 

safety functions in accordance with the 

requirements in the following table. You 

must conduct all tests using the test 

procedure specified in the appropriate 

subsection of API RP 14C, appendix D, 

section D4, table D2 (incorporated by 

reference as specified in § 250.198). 

Safety equipment Frequency Subsection If Then you must 

(1) FSV. You must test 

each required FSV, except those installed underwater, for leakage.

At least annually, with no 

more than 13 months 

between tests.

d ........................................ The FSV does not operate 

properly, or if the flow 

rate exceeds 200 cubic 

centimeters/minute for 

liquid flow or 5 cubic 

feet/minute for natural 

gas flow.

Repair or replae the FSV. 

(2) PSHL sensors. You 

must conduct an external pressure test of each 

required PSHL sensor.

At least monthly, with no 

more than 6 weeks between tests.

g ........................................ (i) The PSHL sensor does 

not operate properly.

(ii) The PSHL sensor set 

pressure tolerance is 

plus or minus 5 percent 

or five psi, whichever is 

greater.

Repair or reglace the 

PSHL sensor. 

Adjust the set point(s) of 

the PSHL sensor. 


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Safety equipment Frequency Subsection If Then you must 

(3) PSV. You must conduct 

an external pressure test 

of each required PSV.

At least annually, with no 

more than 13 months 

between tests.

i ......................................... (i) The PSV does not operate properly.

(ii) The PSV set pressure 

tolerance is plus or 

minus two psi for pressures up to and including 70 psi, or plus or 

minus 3 percent for 

pressures above 70 psi.

Repair or replace the PSV. 

Adjust the set point of the 

PSV. 

(4) SDV. For each required 

SDV, you must conduct 

a(an): 

(i) Operations test ...... At least monthly, with no 

more than 6 weeks between tests.

k (option 1) ........................ The SDV does not operate 

properly.

Repair or replace the SDV. 

(ii) Full valve closure 

test.

At least annually, with no 

more than 13 months 

between tests.

k (option 2) ........................ The SDV does not operate 

properly, or if the flow 

rate exceeds 200 cubic 

centimeters/minute for 

liquid flow or 5 cubic 

feet/minute for natural 

gas flow.

Repair or replace the SDV. 

(iii) Pressure holding 

test.

If required by the Regional 

Supervisor.

Not addressed ................... To be determined by the 

Regional Supervisor.

To be determined by the 

Regional Supervisor. 

(5) SSV. You must conduct 

a pressure holding test 

of each required SSV.

At least monthly, with no 

more than 6 weeks between tests.

m ....................................... The SSV does not operate 

properly, or if any fluid 

flow is observed during 

the test.

Repair or replace the SSV. 

(b) Recordkeeping. You must retain 

the records of the results of the tests 

required by paragraph (a) of this section 

at the nearest OCS facility for at least 2 

years, and make them available to MMS 

upon request. 

§ 250.1085 What must I do when safety 

equipment is removed from service? 

(a) Removal from service notification. 

You must notify the Regional 

Supervisor: 

(1) If the safety equipment remains 

removed from service for more than 12 

hours in the GOMR; or 

(2) Immediately after the safety 

equipment is removed from service in 

the POCSR and AKOCSR. 

(b) Equivalent degree of protection. 

You may continue to operate the 

pipeline only if you: 

(1) Provide an equivalent degree of 

protection; and 

(2) Place an appropriate warning sign 

on the equipment removed from service. 

(c) Follow-up notification. If you are 

required by paragraph (a) of this section 

to notify the Regional Supervisor 

immediately that safety equipment is 

out of service, you must also notify the 

Regional Supervisor immediately in the 

POCSR and AKOCSR, and within 12 

hours in the GOMR, when you return 

the safety equipment to service, or when 

you provide an equivalent degree of 

protection. 

§ 250.1086 What must I do when a pipeline 

is taken out of service? 

(a) Definition. Out-of-service pipeline 

means a pipeline that has not been used 

to transport oil, natural gas, sulphur, or 

produced water for more than 30 

consecutive days. The out-of-service 

period begins on the 31st day of 

inactivity. 

(b) Isolation. You must immediately 

equip an out-of-service pipeline with 

either a blind flange or a block valve 

locked in the closed position at each 

end. 

(c) Safety equipment. During the 30- 

day period of inactivity preceding the 

date that a pipeline attains out-ofservice status, you must maintain and 

test all required pipeline safety 

equipment. 

(d) Out-of-service report. You must 

submit a written report to the Regional 

Supervisor within 48 hours after a 

pipeline attains out-of-service status. In 

the out-of-service report, you must 

include: 

(1) The name of the company 

submitting the report; 

(2) The name and telephone number 

of your contact; 

(3) The MMS-assigned pipeline 

segment number; 

(4) The reason you took the pipeline 

out of service; 

(5) An estimate of the time that the 

pipeline will remain out of service; and 

(6) Confirmation that you have 

isolated the pipeline as required by 

paragraph (a) of this section. 

(e) Flush and fill. When a pipeline is 

out of service for one year, you must: 

(1) Immediately flush the pipeline 

with seawater until the returns comply 

with appropriate EPA NPDES standards; 

(2) Fill the pipeline with inhibited 

seawater; 

(3) Retain the records of your flush 

and fill activities at your nearest OCS 

facility until the pipeline is reactivated; 

(4) Make the records available to 

MMS upon request; and 

(5) If you discharge any returns into 

the water column, dispose of them in 

accordance with applicable laws and 

regulations. 

(f) Reactivation. Before you reactivate 

an out-of-service pipeline, you must test 

all required safety equipment in 

accordance with the procedures in 

§ 250.1084. 

(g) Reactivation report. Within 30 

calendar days after you reactivate an 

out-of-service pipeline, you must submit 

a written report to the Regional 

Supervisor. In the reactivation report, 

you must include the: 

(1) Name of the company preparing 

the report; 

(2) Name and telephone number of 

your contact; 

(3) MMS-assigned pipeline segment 

number; 

(4) Date you returned the pipeline to 

service; and 

(5) Report of the hydrostatic pressure 

test (see § 250.1061(a)), if required by 

§ 250.1060(a)(4). 


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(h) Decommissioning an out-of-service 

pipeline. You must decommission (see 

§§ 250.1105 through 250.1113) a 

pipeline within 1 year after: 

(1) It has been out of service for 5 

years; or 

(2) You determine that it will be out 

of service for 5 years or more. 

§ 250.1087 What must I do if a pipeline is 

shut in? 

Before you resume operations after 

your pipeline was shut in, you must 

determine that the pipeline does not 

leak by conducting a visual survey of 

the pipeline route (see § 250.1103(a)) 

and a leak test (see § 250.1059). These 

requirements are applicable if your 

pipeline was shut in because: 

(a) The eye center path of a major 

storm (winds 74 mph or greater) passed 

within 25 miles (or other distance 

specified by the Regional Supervisor) of 

any part of the pipeline; 

(b) You had indications that pipeline 

integrity may have been compromised; 

or 

(c) Your pipeline had an unexplained 

automatic shut-in (e.g., a PSL shut-in). 

§ 250.1088 What must I do if a pipeline 

leaks? 

If your pipeline experiences an 

accidental leak, you must: 

(a) Immediately suspend operations 

and not resume operations until the 

pipeline is repaired in accordance with 

§§ 250.1094 through 250.1096; and 

(b) Notify the Regional Supervisor 

immediately, or as soon as practicable, 

after you discover that a pipeline is 

leaking. 

§ 250.1089 What must I do if I need to flare 

or vent gas from a pipeline? 

(a) Approval. You must receive 

approval from the Regional Supervisor 

to flare or vent natural gas from your 

pipeline during blowdown, unless the 

blowdown discharge point is 

downstream of the royalty meter (see 

subpart K, redesignated § 250.1155). 

(b) Report. You must submit a written 

report to the Regional Supervisor that 

includes the location, time, flare or vent 

volume, and the reason for flaring or 

venting, within 72 hours after you 

complete the flaring or venting 

operations (see subpart K, redesignated 

§ 250.1155). 

(c) Extended flaring or venting. If you 

need to flare or vent natural gas from a 

pipeline for 48 continuous hours or 

more, you must adhere to the 

requirements in subpart K, redesignated 

§ 250.1155. 

§ 250.1090 When must I provide impact 

protection for existing risers? 

You must provide impact protection 

to all pipeline risers installed prior to 

April 1, 1988, and that are outside of the 

platform structure, whenever: 

(a) The Regional Supervisor 

determines that significant damage 

potential exists; 

(b) You perform maintenance or 

repair operations on any existing 

pipeline riser that is protected by a 

pipe-in-pipe configuration; or 

(c) You perform major repairs or 

modifications on any pipeline riser that 

is not protected. 

§ 250.1091 When will MMS suspend or 

temporarily prohibit pipeline operations? 

The Regional Supervisor may suspend 

or temporarily prohibit any pipeline 

operation if: 

(a) The Regional Supervisor 

determines that continued activity 

would threaten or result in serious, 

irreparable, or immediate harm or 

damage to life (including fish and other 

aquatic life); property; mineral 

resources; or the marine, coastal, or 

human environment; 

(b) The Regional Supervisor 

determines that you have failed to 

comply with a provision of the OCSLA 

or any other applicable law, a provision 

of this part or other applicable 

regulations, or a condition of a pipeline 

application approval or a pipeline ROW 

grant; or 

(c) Prohibiting the pipeline operation 

is in the interest of national security or 

defense. 

Pipeline Modifications and Repairs 

§ 250.1093 What must I do to modify an 

approved pipeline? 

(a) Definition. Modifying a pipeline 

means significantly changing an 

approved pipeline. Modifications 

include changing a pipeline route; 

installing, modifying, or replacing a 

subsea tie-in valve assembly; adding, 

modifying, or replacing safety 

equipment; changing service; changing 

flow direction; installing or replacing a 

pig receiving/launching assembly; 

changing a pipeline riser configuration; 

changing the MAOP; replacing or 

adding anodes; and adding a hot-tap. 

Modifications do not include routine 

operations such as performing a 

hydrostatic pressure test; pigging; 

injecting chemicals; flushing and filling 

a pipeline; installing a blind flange on 

an out-of-service pipeline; installing a 

clamp, sleeve, or wrap to mitigate pipe 

wall loss; and performing other routine 

operations or preventive maintenance. 

(b) Modification application. Before 

you conduct any operations to modify a 

pipeline, you must submit three copies 

of a modification application to the 

Regional Supervisor for approval. In the 

modification application, you must 

include each of the elements required 

by the following paragraphs (b)(1) 

through (b)(7) of this section. 

(1) The MMS-assigned pipeline 

segment number. 

(2) Those items in your approved 

pipeline application (see §§ 250.1014 

through 250.1030) affected by the 

proposed modification. 

(3) The step-by-step procedures you 

will follow in making the modification, 

including the measures you will take to: 

(i) Ensure safety; 

(ii) Minimize pollution; 

(iii) Comply with burial and covering 

requirements; and 

(iv) Perform any required hydrostatic 

pressure or leak test. 

(4) If required by the Regional 

Supervisor, a work plan that describes 

the specific measures you intend to 

take, and the specific procedures you 

intend to follow, to ensure the safety of 

offshore workers and to prevent 

pollution. The work plan must include 

or consider: 

(i) The operating history of the 

pipeline you plan to modify, including 

past modifications or repairs, and the 

operating conditions peculiar to the 

pipeline; 

(ii) Reasonable measures to ensure 

that pressure in the pipeline is equal to 

the external pressure; 

(iii) Reasonable measures to ensure 

that you purge combustibles and H2S 

from the pipeline immediately before 

you conduct the modification; 

(iv) Advance notification to facility 

workers (both company and contract) 

concerning significant aspects of the 

upcoming modification; 

(v) Re-notification of all facility 

workers immediately before you attempt 

to de-pressurize, cut into, or open the 

pipeline to perform the modification; 

(vi) Onsite supervision during the 

entire modification operation; and 

(vii) Safeguards to ensure that the 

pipeline remains isolated during the 

entire modification operation so that 

facility workers are not endangered by 

pressure, H2S, or explosive or 

combustible products. 

(5) Requests for alternative 

compliance (see § 250.141) necessitated 

by the modification. 

(6) If applicable, an electronic file 

containing the digital coordinates of 

sufficient points to provide an accurate 

representation of the proposed modified 

route, including turns, for both the 

pipeline and umbilicals. 

(7) Payment of a nonrefundable 

service fee (see § 250.125 for amount). 

(c) Hot tap modification application. 

If you plan to modify a pipeline by 

installing a hot tap, your modification 

application must include, in addition to 


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the requirements in paragraph (b) of this 

section: 

(1) The design specifications for the 

hot tap; 

(2) A drawing of the proposed hot tap 

assembly; 

(3) A plat that shows the location of 

the hot tap, specifies its location in both 

X–Y coordinates and latitude and 

longitude in NAD 27 for the GOMR 

(Gulf) and POCSR, or NAD 83 for 

AKOCSR and GOMR (Atlantic), and 

shows the water depth (feet); and 

(4) A description of the hot tapping 

operations. 

(d) Affected States. Unless each 

affected State has given general 

concurrence, or the Regional Director 

determines that a State is not an affected 

State, you must provide the information 

required by § 250.1016(a) if your 

planned modification of an approved 

ROW pipeline involves: 

(1) Installation of additional pipe 

(except those modifications that involve 

only minor reconfiguration of existing 

pipelines); 

(2) Installation of a new accessory 

platform; or 

(3) Changing the product from natural 

gas to oil. 

(e) MMS review. A pipeline 

modification application is subject to 

the same review requirements as those 

for a new pipeline application (see 

§ 250.1009). 

(f) Relocation notification. If the 

approved pipeline modification 

involves the relocation of a pipeline, 

you must notify the Regional Supervisor 

at least 48 hours before you begin the 

work, using Form MMS–153 

(Notification of Pipeline Installation/ 

Relocation/Hydrotest). 

(g) Modification report. Within 30 

calendar days after you complete any 

pipeline modification that changed the 

location plat, or that required a 

hydrostatic pressure test, you must 

submit a written modification report to 

the Regional Supervisor. In the 

modification report you must include 

all of the following: 

(1) The MMS-assigned pipeline 

segment number. 

(2) If applicable, a location plat based 

on the NAD 27 for the GOMR (Gulf) and 

POCSR, or NAD 83 for AKOCSR and 

GOMR (Atlantic), at a minimum scale of 

1 inch = 2,000 feet that: 

(i) Depicts the actual location of the 

modification; 

(ii) Includes the latitude and 

longitude coordinates in both NAD 27 

and NAD 83, and the X–Y coordinates 

in NAD 27 for the GOMR (Gulf) and 

POCSR, or NAD 83 for the AKOCSR and 

GOMR (Atlantic), of the key points of 

the modification; and 

(iii) Includes a certification by a 

registered engineer or land surveyor that 

attests to the accuracy of the ‘‘as-built’’

locations of the pipeline as modified. 

(3) If applicable, an electronic file 

containing the digital coordinates of the 

key points of the ‘‘as-built’’ pipeline and 

umbilical routes, including turns, as 

modified. You must report the digital 

data in decimal degrees latitude and 

longitude, based on NAD 83. 

(4) Confirmation that the modification 

was accomplished as approved by the 

Regional Supervisor. 

(5) If applicable, a report of the 

hydrostatic pressure test (see 

§ 250.1061) required by § 250.1060(a)(2), 

(3), or (6). 

(6) If applicable, the pipe-toelectrolyte potential measurements 

required by § 250.1043(b). 

§ 250.1094 What are the general 

requirements for repairing a pipeline? 

Repairing a pipeline means 

performing remedial work as a result of 

a failure and/or the leaking of a pipeline 

or associated equipment, or a reduction 

in wall thickness that would have 

required a reduction in the MAOP. You 

must repair a pipeline in a manner that: 

(a) Meets or exceeds the original 

design specifications of the pipeline, 

appurtenances, and safety system 

components; 

(b) Prevents unauthorized discharges; 

(c) Does not unreasonably interfere 

with other uses of the OCS; and 

(d) Does not cause undue or serious 

harm or damage to the human, marine, 

or coastal environment. 

§ 250.1095 What must I do to commence 

and complete a repair? 

(a) Repair application. Before you 

conduct any repair work on a pipeline, 

you must submit one copy of an 

application to the Regional Supervisor 

for approval. You may submit this 

repair application at the same time as, 

or after, you make the notification 

required by § 250.1088(b). The repair 

application must include all of the 

elements required by the following 

paragraphs (a)(1) through (a)(9) of this 

section. 

(1) The MMS-assigned pipeline 

segment number. 

(2) The location (latitude and 

longitude in NAD 27 for the GOMR 

(Gulf) and POCSR, and in NAD 83 for 

AKOCSR and GOMR (Atlantic)) and 

water depth (feet) of the repair. 

(3) A description of the damaged 

component, and the reason for the 

repair. 

(4) For pipelines that transport 

liquids, an estimate of the volume 

spilled (barrels), including slick size 

and appearance, if applicable. 

(5) For pipelines that transport natural 

gas, an estimate of the volume of gas 

leaked (MMCF), including sheen/boil 

size and appearance, if applicable. 

(6) Specifications of any new pipe, 

spool piece, clamps, or other materials 

you will use in making the repair. 

(7) The step-by-step procedures you 

will follow to make the repair, including 

the measures you will take to: 

(i) Ensure safety; 

(ii) Minimize pollution; 

(iii) Comply with burial and covering 

requirements; and 

(iv) Conduct any required hydrostatic 

pressure or leak test. 

(8) If required by the Regional 

Supervisor, a work plan that describes 

the specific measures you intend to 

take, and the specific procedures you 

intend to follow, to ensure the safety of 

offshore workers and to prevent 

pollution. The work plan must include 

or consider: 

(i) The operating history of the 

pipeline you plan to repair, including 

past modifications or repairs, and the 

operating conditions peculiar to the 

pipeline; 

(ii) Reasonable measures to ensure 

that pressure in the pipeline is equal to 

the external pressure; 

(iii) Reasonable measures to ensure 

that you purge combustibles and H2S 

from the pipeline immediately before 

you commence the repair work; 

(iv) Advance notification to all facility 

workers concerning significant aspects 

of the upcoming repair work; 

(v) Re-notification of all facility 

workers immediately before you attempt 

to de-pressurize, cut into, or open the 

pipeline to perform the repair work; 

(vi) Onsite supervision during the 

entire repair operation; and 

(vii) Safeguards to ensure that the 

pipeline remains isolated during the 

entire repair operation so that facility 

workers are not endangered by the 

release of pressure, H2S, or explosive or 

combustible products. 

(9) Payment of a nonrefundable 

service fee (see § 250.125 for amount). 

(b) MMS review. The Regional 

Supervisor will review the pipeline 

repair application to ensure that the 

proposed operations conform to the 

regulations in this subpart. 

(c) Pressure testing. You must comply 

with the pressure testing requirements 

in § 250.1060(b) and (c). 

(d) Cathodic protection system 

measurements. When you conduct 

underwater repairs, you must measure 

the pipe-to-electrolyte potential at the 

location of the repair site if your 

pipeline: 

(1) Is located in the AKOCSR; or 

(2) Is located in either the GOMR or 

POCSR and either: 


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(i) The pipeline is composed of any 

pipe that is more than 20 years old; or 

(ii) The life expectancy of the 

cathodic protection system cannot be 

calculated. 

(e) Repair report. You must submit a 

written repair report to the Regional 

Supervisor within 30 calendar days after 

you complete a repair. In the repair 

report, you must include: 

(1) The MMS-assigned pipeline 

segment number; 

(2) The actual location of the repair 

(latitude and longitude in NAD 27 for 

the GOMR (Gulf) and POCSR, and in 

NAD 83 for the AKOCSR and GOMR 

(Atlantic)) and water depth (feet); 

(3) Confirmation of the failure or 

damage to the pipeline as originally 

reported to the Regional Supervisor; 

(4) Confirmation that the repair was 

accomplished as approved by the 

Regional Supervisor; 

(5) For pipelines that transport 

liquids, an estimate of the volume that 

spilled (barrels), if any, while you 

performed the repair work; 

(6) A report of any hydrostatic 

pressure test (see § 250.1061(a)) required 

by § 250.1060(b) and (c); 

(7) The results of any leak test (see 

§ 250.1061(b)) required by 

§ 250.1060(b)(1) or (c)(1); and 

(8) The pipe-to-electrolyte potential 

measurements required by paragraph (d) 

of this section. 

(f) Failure analysis and examination. 

The Regional Supervisor may require 

you to analyze a pipeline failure, and 

examine samples of a failed pipe or 

associated equipment in a laboratory to 

determine the cause of failure. When so 

directed, you must submit a 

comprehensive written report of your 

findings to the Regional Supervisor. 

§ 250.1096 What must I do to repair a 

pipeline using a clamp? 

When repairing a pipeline using a 

clamp, you must comply with the 

requirements in the following table: 

If you use . . . Then . . . 

(a) A clamp to make a repair on a pipeline ....... You must use a full encirclement clamp with a rated working pressure equal to or greater than 

the MAOP of the pipeline. 

(b) A clamp on the horizontal component or on 

the riser below the splash zone.

You may use a welded clamp or a mechanical clamp. 

(c) A mechanical clamp to temporarily repair a 

riser in or above the splash zone.

You must: 

(1) Submit a repair application (see § 250.1095(a)) to the Regional Supervisor for approval to 

make a permanent repair. 

(2) Within 30 calendar days after you install the mechanical clamp, complete the permanent 

repair using a welded clamp, spool piece, or other method approved by the Regional Supervisor. 

§ 250.1097 When do I need to submit a 

corrective action plan and report? 

(a) Plan. The Regional Supervisor may 

require you to submit a corrective action 

plan for approval if there are internal or 

external conditions that could 

detrimentally affect a pipeline 

including, but not limited to: 

(1) Conditions that might affect the 

performance or integrity of pipeline 

valves and fittings at a subsea tie-in; 

(2) Conditions that could cause 

interference with navigation or other 

uses of the OCS; 

(3) Riser or riser clamp damage; 

(4) Pipeline exposure or 

displacement; or 

(5) Anomalies and metal loss. 

(b) Submittal. You must submit the 

corrective action plan required by 

paragraph (a) of this section to the 

Regional Supervisor. If the remedial 

work under the corrective action plan 

requires MMS approval of a 

modification application (see 

§ 250.1093(a)) or a repair application 

(see § 250.1095(a)), you may include the 

appropriate application in your 

corrective action plan. 

(c) Report. The Regional Supervisor 

may require you to submit a written 

report, within 30 calendar days after 

you complete the corrective action, 

confirming that you carried out your 

corrective action plan as approved. 

Pipeline Surveying, Monitoring and 

Inspection 

§ 250.1100 What are the general 

requirements for surveying, monitoring, 

and inspecting a pipeline? 

You must survey, monitor, and 

inspect all pipelines, including shut in 

pipelines, in a manner that: 

(a) Periodically verifies the integrity 

of the pipeline and risers; 

(b) Prevents unauthorized discharges; 

(c) Does not unreasonably interfere 

with other uses of the OCS; and 

(d) Does not cause undue or serious 

harm or damage to the human, marine, 

or coastal environment. 

§ 250.1101 What must I do to survey and 

monitor a pipeline or route? 

(a) Surveying. You must conduct a 

visual survey of each of your pipeline 

routes at least monthly (or at a 

frequency specified by the Regional 

Supervisor) for indication of pipeline 

leaks. You may conduct this visual 

survey from a helicopter, marine vessel, 

or vehicle; by walking on ice; or by 

other means approved by the Regional 

Supervisor. The survey must be 

conducted during daylight hours 

(except in the AKOCSR). You must 

retain the results of the visual survey for 

at least 2 years, and make them 

available to MMS upon request. 

(b) Product monitoring. You must 

monitor the products transported in the 

pipeline to ensure that your internal 

corrosion and flow assurance measures 

remain effective. 

§ 250.1102 What inspections are required 

for my pipeline or route? 

You must conduct the inspections in 

the following table: 


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Component and conditions for inspection Inspection requirements Reporting and recordkeeping requirements 

(a) All risers ........................................................ You must: 

(1) Conduct a visual inspection of each pipeline riser in and above the splash zone at 

least annually for indications of damage or 

corrosion.

(2) In conjunction with the platform inspections required by § 250.919, inspect the underwater portions of each pipeline riser for 

indications of corrosion, soil erosion, or 

damage.

You must retain the records of the riser inspections for at least 2 years on the nearest OCS facility, and make them available 

to MMS upon request. 

(b) All flexible joints on risers ............................. You must: 

(1) Conduct a visual inspection of the flexible 

joints on each riser at least annually.

(2) If the results of an inspection required by 

item (1) of this paragraph indicate that a 

flexible joint shows signs of deterioration, 

conduct the required inspections at least 

every 6 months.

You must submit the results of each flexible 

joint inspection to the Regional Supervisor 

within 30 calendar days after you complete 

the inspection. 

(c) Impressed current sources if your pipeline is 

protected by rectifiers or other impressed current sources.

You must inspect the impressed current 

sources at least six times each year (with 

no more than 10 weeks between inspections) to determine if the pipeline is adequately protected.

You must retain the records of the impressed 

current source inspections for at least 2 

years on the nearest OCS facility, and 

make them available to MMS upon request. 

(d) Anode systems if your pipeline is cathodically protected by anodes and if your pipeline 

is: 

You must measure the pipe-to-electrolyte potential annually by September 30 of each 

year.

You must submit the pipe-to-electrolyte potential measurements to the Regional Supervisor no later than October 31 of the same 

year, or within 60 calendar days of the 

measurements, whichever is earlier. 

(1) Located in the POCSR or AKOCSR; or 

(2) Located in the GOMR and either: 

(i) The pipeline is composed of any 

pipe that is more than 20 years old; 

or 

(ii) The life expectancy of the cathodic 

protection system cannot be calculated. 

§ 250.1103 What additional inspections or 

surveys may the Regional Supervisor 

require? 

The Regional Supervisor may require 

you to conduct the inspections or 

surveys in the following table: 

Type of inspection the regional supervisor may 

require Inspection requirements Reporting and record keeping requirements 

(a) Horizontal components inspection ................ Conduct a visual or remote inspection of the 

horizontal component of your pipeline.

Submit a report on the results of the horizontal component inspection to the Regional Supervisor. The Regional Supervisor 

will specify the contents and submittal 

deadline of the report. 

(b) Pipeline inspection after a storm. If any portion of your pipeline within 25 miles (or other 

distance specified by Regional Supervisor) of 

the eye (central path) of a major storm (74 

mph or greater).

(1) Survey the pipeline route ...........................

(2) Conduct a visual inspection of the abovewater portion of the pipeline riser for damage to the riser and clamps.

(3) Inspect the underwater portion of the pipeline riser (including clamps, VIV suppression, and connection devices) for evidence 

of displacement or exposure.

Submit a report of the results of the poststorm inspection(s) listed in this paragraph 

to the Regional Supervisor. The Regional 

Supervisor will specify the contents and 

submittal deadline of the report. 

(4) Inspect the horizontal component from the 

base of the riser to a point at least 200 feet 

away from the base of the riser for evidence of displacement or exposure.

(5) Conduct an underwater visual inspection 

by divers or ROV of each of your pipeline 

valves, crossings, and tie-ins to determine: 

(i) Whether or not any valves or fittings became exposed; and.


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Type of inspection the regional supervisor may 

require Inspection requirements Reporting and record keeping requirements 

(ii) The extent of any damage, including 

damage to protective devices, mats, and 

sandbags.

(c) Pipeline Inspection after an earthquake. If 

any portion of your pipeline mayhave been 

affected by an earthquake.

Conduct surveillance, inspection, and monitoring of the pipeline.Submit a report on the results of the postearthquake surveillance, inspections, or 

monitoring to the Regional Supervisor. The 

Regional Supervisor will specify the contents and submittal deadline of the report. 

(d) Ultrasonic test (UT) inspection ..................... Conduct a UT inspection of your pipeline ....... Submit a report on the UT inspection results 

to the Regional Supervisor. The Regional 

Supervisor will specify the contents and 

submittal deadline of the report. 

(e) In-line inspection ........................................... Conduct an in-line inspection of your pipeline 

using smart pigs.

Submit a report on results of the in-line inspection to the Regional Supervisor. The 

Regional Supervisor will specify the contents and submittal deadline of the report. 

(f) Trawl test or other survey .............................. Conduct a trawl test, diver survey, or ROV 

survey, or use another method approved by 

the Regional Supervisor, to determine 

whether the pipeline interferes with other 

uses of the OCS.

Submit a report on the results of the trawl 

test, diver survey, or ROV survey to the Regional Supervisor. The Regional Supervisor 

will specify the contents and submittal 

deadline of the report. 

Pipeline Decommissioning 

§ 250.1105 When do I accrue pipeline 

decommissioning obligations? 

You accrue pipeline decommissioning 

obligations when you are, or become: 

(a) A lessee, or the owner of operating 

rights, of a lease on which there is a 

lease term pipeline; or 

(b) The holder of a pipeline ROW on 

which there is a pipeline, accessory, or 

appurtenance (including umbilicals). 

§ 250.1106 When must I decommission a 

pipeline? 

You must decommission your 

pipeline within 1 year after: 

(a) The pipeline has been out of 

service for 5 years (see § 250.1086(h)(1)); 

(b) You determine that a pipeline will 

be out of service for 5 years or more (see 

§ 250.1086(h)(2)); 

(c) For ROW pipelines, your pipeline 

ROW grant terminates (see 

§ 250.1138(b)); or 

(d) For lease term pipelines, your OCS 

lease terminates. 

§ 250.1107 What must I do to 

decommission a pipeline in place? 

You may decommission a pipeline in 

place when the Regional Supervisor 

determines that the pipeline does not 

constitute a hazard or obstruction to 

navigation and commercial fishing 

operations, unduly interfere with other 

uses of the OCS, or have adverse 

environmental effects. To decommission 

a pipeline in place you must meet the 

requirements in the following table. 

Requirement What you must do to meet the requirement 

(a) Application ...................... Submit a pipeline decommissioning application to the Regional Supervisor in accordance with § 250.1109(a)(1), 

and receive approval from the Regional Supervisor before you begin the work. 

(b) Purging and flushing ....... (1) You must either: 

(i) Pig the pipeline, including risers, using a pig that will displace the entire contents of the pipeline; or 

(ii) Flush the pipeline, including risers, with seawater until the returns comply with appropriate EPA NPDES standards. 

(2) If you discharge any flushed returns into the water column, you must dispose of them in accordance with applicable laws and regulations. 

(c) Filling ............................... Fill the pipeline, including risers, with seawater. 

(d) Records .......................... For each pipeline decommissioned in place after (INSERT THE EFFECTIVE DATE OF THE REGULATION), retain the records of your flushing and filling activities and make them available to MMS upon request for the life 

of the pipeline. 

(e) Disconnecting ................. Disconnect the pipeline from connecting platforms, pipelines, and subsea manifolds. 

(f) Cutting and plugging ....... Cut and plug each end of the pipeline. 

(g) Protecting ends ............... Protect the ends of the pipeline as follows: 

(1) If the pipeline end is in a water depth less than 200 feet, bury the end to a depth at least 3 feet below the 

seafloor, and cover it with either sand bags or a concrete mat. If you use sand bags, they must have a slope 

above the seafloor of 1:3 (rise:run). If you use a concrete mat, the edges of the mat must be below the 

seafloor. 

(2) If the pipeline end is in a water depth 200 feet or greater but less than 500 feet, you may either bury the end 

to a depth at least 3 feet below the seafloor, or cover the end with a concrete mat. If you use a concrete mat, 

the edges of the mat must be below the seafloor. 

(3) If the pipeline end is in a water depth 500 feet or greater, you may forego burial and covering if the Regional 

Supervisor determines that the pipeline end is not an obstruction to other uses of the seafloor or area. 

(h) Removing appurtenances Remove all pipeline appurtenances unless: 

(1) The Regional Supervisor determines that the appurtenance would not unduly interfere with other uses of the 

seafloor or area; or 

(2) The water depth is greater than 2,624 feet. 

(i) Decommission umbilicals 

in place.

Decommissioning all umbilicals in place in accordance with the requirements of paragraphs (a) through (g) of this 

section. 


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§ 250.1108 What must I do to 

decommission a pipeline by removal? 

To decommission a pipeline by 

removal, you must: 

Requirement What you must do to meet the requirement 

(a) Application ...................... Submit a pipeline decommissioning application to the Regional Supervisor in accordance with § 250.1109(a)(2), 

and receive approval from the Regional Supervisor before you begin the work. 

(b) Purging and flushing ....... (1) You must either: 

(i) Pig the pipeline, including risers, using a pig that will displace the entire contents of the pipeline; or 

(ii) Flush the pipeline, including risers, with seawater until the returns comply with appropriate EPA NPDES standards. 

(2) If you discharge any flushed returns into the water column, you must dispose of them in accordance with applicable laws and regulations. 

(c) Removing umbilicals ....... Remove all umbilicals in accordance with the requirements of paragraphs (a) and (b) of this section. 

(d) Removing the pipeline .... Physically remove the pipeline. 

§ 250.1109 How do I obtain approval to 

decommission a pipeline? 

(a) To obtain approval to 

decommission a pipeline, you must: 

What to submit Application contents 

(1) Submit three copies of a 

pipeline decommissioning 

application to the Regional 

Supervisor for approval.

(i)The MMS-assigned pipeline segment number; 

(ii) Reason for the decommissioning; 

(iii) Proposed decommissioning procedures, including those to comply with the requirements of § 250.1107; 

(iv) Length (feet) of pipe to be decommissioned; 

(v) Length (feet) of pipe that will remain in place; 

(vi) Requests for alternative compliance or a departure under §§ 250.141 or 250.142; and 

(vii) If the application is to decommission a lease term pipeline, payment of a nonrefundable service fee (see 

§ 250.125 for amount). 

(2) Submit three copies of a 

pipeline decommissioning 

application to the Regional 

Supervisor for approval.

(i) The MMS-assigned pipeline segment number; 

(ii) The reason for the decommissioning; 

(iii) Your proposed removal procedures, including decommissioning those to comply with the requirements of 

§ 250.1108; 

(iv) A description of the vessel(s) you will use to remove the pipeline, including anchor pattern(s), if required by 

the Regional Supervisor. 

(v) The length (feet) of pipe to be removed; 

(vi) The length (feet) of pipe that will remain in place; 

(vii) Plans for transportation of removed pipe for disposal or salvage; 

(viii) Plans to protect archaeological and sensitive biological features during removal operations; 

(ix) An assessment of the environmental impacts of the removal operations, and the procedures and mitigation 

measures that you will take to minimize such impacts; 

(x) A projected pipeline removal schedule; 

(xi) If the application is to decommission an ROW pipeline by removal: 

(A) A coastal zone consistency certification according to 15 CFR 930.57, for each affected State; and 

(B) Evidence that you have sent your decommissioning application, consistency certification (see 15 CFR 

930.57), and all necessary data and information (see 15 CFR 930.58) to each affected State for their consistency determination under the CZMA; and 

(xii) If the application is to decommission a lease term pipeline, payment of a nonrefundable service fee (see 

§ 250.125 for amount). 

(b) Electronic submission. You may 

submit part or all of your 

decommissioning application 

electronically (see § 250.186(a)(3)). If 

you prefer to submit your application 

electronically, you should consult with 

the Regional Supervisor for further 

guidance. 

(c) Withdrawal of application. You 

may withdraw your decommissioning 

application at any time, for any reason, 

by notifying the Regional Supervisor in 

writing. 

§ 250.1110 How does MMS process a 

decommissioning application? 

After you submit a decommissioning 

application, the Regional Supervisor 

will process it as shown in the following 

table. 

Processing step What the Regional Supervisor will do 

(a) Completeness review. .... Determine whether your decommissioning application (either in place or by removal) is complete, and will notify 

you in writing of any problem or deficiency. The Regional Supervisor will not begin processing your application 

until it is complete. 

(b) Compliance review ......... Review the proposed operations described in your decommissioning application to ensure that they conform to 

the OCSLA (43 U.S.C.1331, et seq.), other applicable laws, and MMS regulations. 


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Processing step What the Regional Supervisor will do 

(c) Environmental impact 

evaluation.

Evaluate the environmental impacts of the operations described in your decommissioning application, and prepare environmental documentation under NEPA (42 U.S.C. 4321, et seq.) and the implementing regulations (40 

CFR parts 1500 through 1508). 

(d) Amendments ................... During the review of your decommissioning application, the Regional Supervisor may require you, or you may 

elect, to change the application. 

(e) MMS decision ................. Review your decommissioning application, notify you in writing of the decision, and either: 

(1) Approve the application, if it complies with all applicable requirements, and inform you of any conditions of approval; or 

(2) Require you to amend the application, and inform you of the reasons for requiring the amendment, if the proposed decommissioning operations would probably cause serious harm or damage to life (including fish or 

other aquatic life); property; mineral resources (in areas leased or not leased); the national security or defense; 

or the marine, coastal, or human environment. 

§ 250.1111 After I decommission a 

pipeline, what information must I submit? 

Within 30 calendar days after you 

decommission a pipeline, you must 

submit a written decommissioning 

report to the Regional Supervisor that 

includes: 

(a) The MMS-assigned pipeline 

segment number; 

(b) A summary of the 

decommissioning operation, including 

the date the work was completed; 

(c) A description of any mitigation 

measures you took; and 

(d) A statement signed by your 

authorized representative which 

certifies that the pipeline was 

decommissioned according to the 

approved application. 

§ 250.1112 When must I remove a pipeline 

decommissioned in place? 

If the Regional Supervisor 

subsequently determines that the 

pipeline decommissioned in place is an 

obstruction to other uses of the OCS, 

you must remove the pipeline in 

accordance with the requirements in 

§§ 250.1108, 1109(a)(2), and 1111. 

§ 250.1113 What are the requirements for 

re-commissioning a decommissioned 

pipeline? 

(a) Re-commissioning. Before recommissioning a decommissioned 

pipeline, the current lessee, current 

designated lease operator, or former 

pipeline ROW holder, as applicable, 

must: 

(1) Submit an application under 

§ 250.1007(a), including the MMSassigned pipeline segment number, and 

receive approval from the Regional 

Supervisor. 

(2) If the application is to recommission a pipeline as an ROW 

pipeline, include: 

(i) An application for a pipeline ROW 

grant, if applicable (see § 250.1125(a)), 

and receive approval from the Regional 

Supervisor; and 

(3) Hydrostatically pressure test the 

pipeline in accordance with 

§ 250.1060(a)(5). 

(4) Conduct all inspections required 

by the Regional Supervisor, including 

those in § 250.1102(b), (c), and (d) and 

§ 250.1103(a), (d), and (e). 

(b) Re-commissioning report. Within 

30 calendar days after you recommission a decommissioned 

pipeline, you must submit a written recommissioning report to the Regional 

Supervisor that includes all of the 

following: 

(1) The MMS-assigned pipeline 

segment number. 

(2) A location plat based on the NAD 

27 for the GOMR (Gulf) and POCSR, or 

NAD 83 for AKOCSR and GOMR 

(Atlantic), at a minimum scale of 1 inch 

= 2,000 feet. The location plat must 

depict the actual location of the recommissioned pipeline. 

(3) An electronic file of the digital 

coordinates of the key points of your 

‘‘as-built’’ pipeline route, as recommissioned. You must report the 

digital data in decimal degrees latitude 

and longitude, based on NAD 83. 

(4) Confirmation that the recommissioning was accomplished as 

approved by the Regional Supervisor. 

(5) A report of the hydrostatic 

pressure test (see § 250.1061) required 

by § 250.1060(a)(5). 

Pipeline Right-of-Way (ROW) Grants 

§ 250.1115 What is a pipeline ROW grant? 

A pipeline ROW grant is an 

authorization issued by MMS for the use 

of submerged lands for the construction 

and operation of an associated ROW 

pipeline to transport oil, natural gas, 

sulphur, or other associated products. 

(a) Authority. MMS grants a pipeline 

ROW pursuant to section 5(e) of the 

OCSLA (43 U.S.C. 1334(e)). 

(b) Term. A pipeline ROW granted by 

MMS under the provisions of this 

subpart remains in effect until it is 

relinquished, cancelled, or forfeited, or 

until it expires. 

(c) Dimensions. A pipeline ROW 

includes the site on which the pipeline, 

and any associated appurtenances and 

accessories, are or will be situated. 

(1) The width of the pipeline ROW is 

200 feet centered on the pipeline. 

(2) The site of an accessory includes 

the areal extent of anchor chains, 

pipeline risers, and other facilities and 

devices associated with the accessory. 

(d) Conveyed rights. If the Regional 

Supervisor approves a pipeline ROW 

grant, you have the: 

(1) Exclusive right and privilege to 

construct, maintain, and operate the 

associated pipeline for the purpose of 

transporting oil, natural gas, sulphur, or 

other associated products; and 

(2) Right to be notified and consulted 

if any proposed OCS operations will 

cross or otherwise impact your pipeline 

ROW. 

§ 250.1116 When must I obtain a pipeline 

ROW grant? 

Before you may construct an ROW 

pipeline, or use an existing pipeline that 

qualifies as a ROW pipeline, the 

Regional Supervisor must grant you a 

pipeline ROW in accordance with the 

provisions of this subpart. You must 

receive a separate pipeline ROW grant 

for each ROW pipeline, even if the new 

pipeline ROW grant would overlap 

another pipeline ROW grant. 

§ 250.1117 Who can be a pipeline ROW 

grant holder? 

(a) Entities. A pipeline ROW holder 

must be one of the following: 

(1) A citizen or national of the United 

States; 

(2) An alien lawfully admitted for 

permanent residence in the United 

States as defined in 8 U.S.C. 1101(a)(20); 

(3) A private, public, or municipal 

corporation recognized by the United 

States and organized under the laws of 

the United States or a territory thereof, 

the District of Columbia, or any State; or 

(4) An association (including a 

partnership) of such citizens, nationals, 

resident aliens, or private, public, or 

municipal corporations. 

(b) Qualification file. In the pipeline 

ROW grant application required by 

§ 250.1125(a), you may reference 

statements and records you previously 


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submitted to an MMS OCS Region 

regarding incorporation, and the 

person(s) authorized to act on behalf of 

your corporation or association (see 

§ 250.1126(b) and (c)) and to receive 

process and notifications. The Regional 

Supervisor will maintain this 

information in a qualification file. If you 

choose to establish a qualification file, 

you must ensure that it contains 

accurate and up-to-date information to 

avoid delays in reviewing your pipeline 

ROW grant application. 

(c) Disqualification. The Director may 

disqualify you from acquiring any new 

pipeline ROW grants, or from holding 

any existing pipeline ROW grants, if 

your operating performance is 

unacceptable. The Director will give you 

notice and an opportunity for a review 

by MMS before disqualifying you. 

§ 250.1118 What are the financial security 

requirements for holding a pipeline ROW 

grant? 

(a) ROW grant financial security. You 

(the applicant) must furnish the 

Regional Director with a bond or other 

security in the sum of $300,000 for each 

pipeline ROW grant you hold. This 

security is in addition to any security 

required of a lessee by 30 CFR 256, 

subpart I, Bonding. 

(b) ROW grant area financial security. 

In lieu of providing the security 

required by paragraph (a) of this section, 

you may maintain with the Regional 

Director, or furnish to the Regional 

Director, a bond or other security in the 

sum of $1 million that covers all of the 

pipeline ROW grants you hold in an 

MMS OCS Region. The following table 

shows MMS regions and the areas they 

encompass. 

MMS OCS regions are . . . For OCS areas adjacent to the . . . 

(1) Alaska OCS Region (AKOCSR). ........................................................ State of Alaska. 

(2) Gulf of Mexico OCS Region (GOMR). ............................................... Atlantic Coast States or in the Gulf of Mexico. 

(3) Pacific OCS Region (POCSR). ........................................................... States of California, Oregon, Washington, or Hawaii. 

(c) Additional financial security. The 

Regional Director may require you to 

provide additional security (i.e., 

security above the sum of $300,000 

specified in paragraph (a) of this 

section, or the sum of $1 million 

specified in paragraph (b) of this 

section). 

(1) The Regional Director will base the 

determination and the amount of 

additional security on an evaluation of 

your ability to carry out present and 

future financial obligations under the 

pipeline ROW grant, including your 

obligation to maintain and remove an 

accessory to the ROW pipeline. 

(2) During the evaluation, the 

Regional Director will give you an 

opportunity to submit written or oral 

statements. 

(3) If the Regional Director requires 

additional security, you may either 

increase the amount of your existing 

bond or other security, or provide a 

supplemental bond(s) or other security. 

(d) General requirements. Any bond 

or other security you provide under this 

section must: 

(1) Be submitted on Form MMS–2030 

(Outer Continental Shelf (OCS) Pipeline 

Right-of-Way Grant Bond); 

(2) Be payable upon demand to the 

Regional Director; 

(3) Guarantee your compliance with 

the terms and conditions of the pipeline 

ROW grant, your obligations under the 

grant, the OCSLA (43 U.S.C.1331, et 

seq.), other laws, and applicable MMS 

regulations; 

(4) If the security is a bond, be issued 

by a surety that the U.S. Department of 

the Treasury certifies as an approved 

surety on Federal bonds and that is 

listed in the current Treasury Circular 

No. 570; 

(5) If the security is a bond, be 

executed by authorized officials 

representing you and the surety; 

(6) If the surety is a corporation, be 

signed by an authorized corporate 

officer and attested to with its embossed 

corporate seal; and 

(7) Be non-cancelable, except as 

provided in §§ 250.1120 and 250.1124. 

(e) State law. If the security is a bond, 

the bond must continue in full force and 

effect even if the surety’s obligation has 

been diminished, terminated, or 

canceled under State law. 

§ 250.1119 When will MMS terminate the 

period of liability of my financial security? 

The Regional Director will not 

terminate the period of liability of your 

bond or other security for a pipeline 

ROW grant except under the conditions 

in this section. 

(a) If your surety requests termination 

of liability from the Regional Director, 

the Regional Director will approve the 

request and terminate that period of 

liability within 90 calendar days after 

receipt of the request. 

(b) If you intend to maintain the 

pipeline ROW grant, or have not 

fulfilled all decommissioning or other 

obligations, you must provide the 

Regional Director with a replacement 

bond or other security of equivalent 

value. 

(c) When the Regional Director 

terminates the period of liability of a 

bond or other security, the period 

during which obligations continue to 

accrue ends. This termination does not 

relieve the surety of the responsibility 

for obligations and responsibilities that 

accrued during the period of liability 

and before the date of termination. The 

obligations and responsibilities that 

accrue during a period of liability also 

include those that began accruing before 

the beginning of the period of liability 

and have not been fulfilled. 

(d) If the Regional Director terminates 

the period of liability, but the bond or 

other security is not cancelled, the 

surety that provided the bond will 

continue to be liable for accrued 

obligations until they have been 

fulfilled. 

§ 250.1120 When will MMS cancel my 

financial security? 

The Regional Director will cancel 

your bond or other security, and thus 

relieve the surety of accrued obligations, 

only if you request cancellation from the 

Regional Director and either: 

(a) The Regional Director determines 

that there are no outstanding 

obligations; or 

(b) You provide the Regional Director 

with a replacement bond or other 

security of equivalent value in which: 

(1) The new surety agrees to assume 

all outstanding liabilities under the 

bond or other security to be cancelled; 

and 

(2) The new bond or other security is 

in an amount equal to or greater than 

the bond or other security to be 

cancelled. 

§ 250.1121 What happens if my financial 

security is reduced or lapses? 

(a) Reduced financial security value. 

If the value of a required pipeline ROW 

grant bond or other security is reduced 

because of a default, or for any other 

reason, you must provide the Regional 

Director with additional coverage 

sufficient to meet the security required 

by § 250.1118(a) or (b) and, if 

applicable, § 250.1118(c). You must 

provide this additional coverage within 

30 calendar days, or within a shorter 

period if required by the Regional 


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Director, after the value of your security 

coverage is reduced. 

(b) Lapse of financial security. If your 

surety is decertified by the Department 

of the Treasury, becomes bankrupt or 

insolvent, or has its charter or license 

suspended or revoked, your security 

coverage terminates immediately. In 

that event, you must: 

(1) Notify the Regional Director 

within 72 hours; and 

(2) Provide the Regional Director with 

a new bond or other security sufficient 

to meet the security required by 

§ 250.1118(a) or (b) and, if applicable, 

§ 250.1118(c) You must do this within 

15 calendar days after your security 

coverage terminates, or within a shorter 

period if required by the Regional 

Director. 

§ 250.1122 How will MMS determine that 

my financial security is forfeited? 

(a) The Regional Director will pursue 

forfeiture of all or part of your bond(s) 

or other security if the Regional Director 

finds that either: 

(1) You refuse, or are unable, to 

comply with the terms and conditions 

of the pipeline ROW grant, your 

obligations under the grant, the OCSLA 

(43 U.S.C. 1331, et seq.), other laws, or 

applicable MMS regulations; or 

(2) You have otherwise defaulted 

under any condition imposed when the 

Regional Director accepted the bond or 

other security. 

(b) The Regional Director may pursue 

forfeiture of your bond(s) or other 

security without first making demands 

for performance against you. 

(c) In pursuing forfeiture of your 

bond(s) or other security, the Regional 

Director will: 

(1) Notify you and your surety in 

writing that the forfeiture process has 

begun, and include the reasons for the 

forfeiture and the amount to be 

forfeited; 

(2) Base the amount to be forfeited on 

an estimate of the total cost to bring 

your pipeline ROW grant into 

compliance, or to correct any default; 

and 

(3) Advise you and your surety in 

writing that you may avoid forfeiture if, 

within 5 working days either: 

(i) You agree to, and demonstrate that 

you will, bring your pipeline ROW grant 

into compliance or correct any default 

within a timeframe prescribed by the 

Regional Director; or 

(ii) Your surety agrees to, and 

demonstrates that it will, bring your 

pipeline ROW grant into compliance or 

correct any default within a timeframe 

prescribed by the Regional Director, 

even if the cost of compliance or 

correcting the default exceeds the 

amount of your bond or other security. 

(d) If you or your surety refuse, or are 

unable, to comply with the conditions 

in paragraph (c)(3) of this section, the 

Regional Director will determine that 

your bond or other security is forfeited, 

and will: 

(1) Collect the forfeited amount; 

(2) Use the collected funds to bring 

your pipeline ROW grant into 

compliance, or to correct any default; 

(3) Initiate proceedings to recover 

from you all costs in excess of the 

amount the Regional Director collected 

from your forfeited bond or other 

security, if the collected funds are 

insufficient to bring your pipeline ROW 

grant into compliance or to correct any 

default; and 

(4) Return any funds collected from 

the forfeited bond or other security that 

were not used to bring your pipeline 

ROW grant into compliance or to correct 

any default. 

(e) If your bond or other security is 

forfeited, you must furnish the Regional 

Director with a new bond or other 

security sufficient to meet the security 

required by § 250.1118(a) or (b) and, if 

applicable, § 250.1118(c). You must do 

this within 15 calendar days after your 

bond or other security was forfeited, or 

within a shorter period if required by 

the Regional Director. 

§ 250.1123 What penalties can MMS 

assess if my financial security is not 

sufficient, is reduced or lapses, or is 

forfeited? 

If you fail to provide any additional 

security required by the Regional 

Director (under § 250.1118(c)), replace 

or provide additional coverage for a 

devalued bond or other security (under 

§ 250.1121(a)), or replace a lapsed or 

forfeited bond or other security (under 

§ 250.1121(b) or § 250.1122), then: 

(a) The Regional Director may assess 

penalties under 30 CFR 250, subpart N, 

Outer Continental Shelf (OCS) Civil 

Penalties; 

(b) The Regional Supervisor may 

suspend the pipeline ROW grant in 

accordance with § 250.1135(b); and 

(c) The Secretary may cancel the 

pipeline ROW grant in accordance with 

§ 250.1137(a)(4). 

§ 250.1124 What happens to my financial 

security after a pipeline ROW grant 

terminates? 

When your pipeline ROW grant 

terminates (either by relinquishment, 

cancellation, forfeiture, or expiration), 

your surety(s) remains responsible, and 

the Regional Director will retain your 

bond or other financial security as 

shown in the following table: 

For . . . the period of liability ends . . . and . . . 

(a) Securities provided under 

§ 250.1118(a) or (b).

When the Regional Director determines that you have fulfilled all 

of your obligations under the 

pipeline ROW grant.

(1) The Regional Director will cancel your financial security 7 years 

after the pipeline ROW grant terminates; 6 years after you complete all secured obligations; or at the conclusion of any appeals or 

litigation related to your secured obligation, whichever is the latest. 

(2) The Regional Director will reduce the amount or return a portion 

of your bond or other security if the Regional Director determines 

that a lesser amount is required to cover any unforeseen events 

under your accrued obligations. 

(b) Additional securities provided 

under § 250.1118(c).

When the Regional Director determines that you have fulfilled all 

of your obligations covered by 

the additional security.

The Regional Director will cancel your financial security either: 

(1) When you meet your secured obligations; or 

(2) Seven years after the pipeline ROW grant terminates; if the Regional Director determines that the amount required to cover unforeseen events under your accrued obligations is greater than the 

amount of the security you provided under § 250.1118(a) or (b); or 

(3) At the conclusion of any appeals or litigation related to your secured obligation; whichever is the latest. 


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§ 250.1125 How do I submit an application 

for a pipeline ROW grant? 

(a) Application. You must submit one 

original and two copies of an 

application for a pipeline ROW grant to 

the Regional Supervisor. You must 

attach the ROW grant application to the 

application for the associated ROW 

pipeline (see § 250.1007(a)), and include 

the information required by § 250.1126 

in your ROW grant application. 

(b) Service fee. With each pipeline 

ROW grant application you submit, 

including an application for a pipeline 

ROW grant to convert an existing lease 

term pipeline to an ROW pipeline or an 

application to for an ROW grant for an 

existing pipeline, you must include 

payment of the applicable 

nonrefundable service fee (see § 250.125 

for the amount). 

(c) Submitting additional information. 

The Regional Supervisor may require 

your ROW grant application to include 

information in addition to that required 

by § 250.1126, if the Regional 

Supervisor determines that it is 

necessary to evaluate the application. 

(d) Electronic submission. You may 

submit part or all of your pipeline ROW 

grant application electronically (see 

§ 250.186(a)(3)). If you prefer to submit 

your pipeline ROW grant application 

electronically, you should consult with 

the Regional Supervisor for further 

guidance. 

(e) Withdrawal of application. You 

may withdraw your pipeline ROW grant 

application at any time, and for any 

reason, by notifying the Regional 

Supervisor in writing. 

§ 250.1126 What information must I 

include in an application for a pipeline ROW 

grant? 

(a) Cover letter. You must provide a 

cover letter that states: 

(1) You are submitting the pipeline 

ROW grant application pursuant to 

section 5 of the OCSLA (43 U.S.C. 

1334(e)) or section 8 of the OCSLA (43 

U.S.C. 1337(p)(1)(B)) and the regulations 

contained in 30 CFR 250, subpart J; 

(2) You consent to be bound by the 

provisions of the OCSLA (43 U.S.C. 

1331, et seq.) and other applicable laws, 

MMS regulations, and the terms and 

conditions of the pipeline ROW grant; 

(3) The purpose(s) for which you will 

use the pipeline ROW grant; and 

(4) The name, title, and signature of 

your authorizing official. This 

information must be the same as the 

information you provide or reference in 

your MMS qualification records (see 

§ 250.1117(b)). 

(b) Qualification. You must provide 

information regarding your qualification 

to be a pipeline ROW holder as follows: 

If you are . . . You must provide . . . 

(1) An individual ........................................................................................ A statement of citizenship or nationality. 

(2) An alien lawfully admitted for permanent residence in the United 

States.

Evidence of such status. 

(3) A corporation ....................................................................................... (i) A statement certified by the Secretary or Assistant Secretary of the 

corporation with the corporate seal showing the State where it is incorporated; and 

(ii) The name(s), title(s), and signature(s) of the person(s) authorized to 

act on behalf of the corporation. 

(4) An association (including a partnership) ............................................ (i) A certified copy of the articles of association; and 

(ii) The name(s), title(s), and signature(s) of the person(s) authorized to 

act on behalf of the association. 

(c) Reference to qualification records. 

In lieu of providing the information 

required by paragraphs (b)(3) and (4) of 

this section, you may reference 

statements and records you previously 

submitted to MMS regarding the 

corporation or association, and the 

persons authorized to act on behalf of 

the corporation or association (see 

§ 250.1117(b)). If you choose this 

alternative, you must state that the 

company official who signed the cover 

letter has the authority to: 

(1) Submit the pipeline ROW grant 

application; 

(2) Bind the corporation or association 

to compliance with the terms and 

conditions of the pipeline ROW grant; 

and 

(3) Bind the corporation or association 

to compliance with the various 

statements and certifications made in 

your pipeline ROW grant application. 

(d) Identified ROW pipeline operator. 

If the pipeline ROW grant holder will 

not be the operator of the associated 

pipeline, you must identify the operator 

and provide its MMS company number, 

if any. 

(e) Bond or other financial security. 

You must describe your bond or other 

security coverage for the proposed 

pipeline ROW (see § 250.1118(a) or (b)). 

(f) Additional financial security. If the 

Regional Director determines that you 

must provide additional security, you 

must describe such security (see 

§ 250.1118(c)). 

(g) Accessory footprint. If your 

pipeline ROW will include a site for an 

accessory, you must provide the size of 

the affected area (acres), and 

information that shows how you 

determined the size (see 

§ 250.1130(a)(2)) and the maximum 

water depth. 

(h) Payments. You must include your 

service fee and rental payments, made 

payable to the Minerals Management 

Service. If you pay by credit card, follow 

the instructions in § 250.125(b)(1). If 

you pay by check, your check must 

identify the check number, date, and 

name of the financial institution upon 

which the check is written. You must 

provide additional information that 

includes: 

(1) Total amount of the service fee 

(see § 250.125(b)); 

(2) Total amount of the pipeline 

rental, and the time period it covers (see 

§ 250.1130(a)(1)); 

(3) Total amount of rental for an 

accessory site (if applicable), and the 

time period it covers (see 

§ 250.1130(a)(2)); and 

(4) Total payment amount. 

§ 250.1127 How does MMS process an 

application for a pipeline ROW grant? 

(a) Compliance review. The Regional 

Supervisor will review your pipeline 

ROW grant application to ensure that it 

complies with the OCSLA (43 

U.S.C.1331, et seq.), other applicable 

laws, and MMS regulations. 

(b) Amendments. During the review of 

your pipeline ROW grant application, 

the Regional Supervisor may require 

you, or you may elect, to change the 

application. 

(c) Decision. The Regional Supervisor 

will review your pipeline ROW grant 

application, and take one of the 

following actions: 


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The Regional Supervisor 

will . . . If . . . And the Regional Supervisor also . . . 

(1) Approve your application 

for a pipeline ROW grant 

in writing.

It complies with all applicable requirements ................... (i) Will simultaneously approve the associated pipeline 

(see § 250.1012(a)) and, if applicable, any associated 

accessory (see § 250.1142(e)(1)); and 

(ii) May require you to meet certain conditions. 

(2) Require you amend your 

application for a pipeline 

ROW grant.

The Regional Supervisor determines that it is inconsistent with the OCSLA (43 U.S.C. 1331, et seq.), 

applicable MMS regulations, or other Federal laws.

Will notify you in writing of the decision, and describe 

the changes you must make to your pipeline ROW 

grant application to ensure it complies with all applicable requirements. 

(3) Deny your application ..... (i) The application for the associated pipeline is disapproved under § 250.1012(b); 

(ii) You do not qualify to hold a pipeline ROW grant, or 

are unable to post the required bonds or other security;.

(iii) You do not comply with applicable requirements, 

and are unable to amend the application to achieve 

compliance; or.

(iv) The proposed pipeline ROW will cross any OCS 

lands (e.g., fairways or anchorage areas) that are 

under the jurisdiction of another Federal agency and 

that agency does not consent to the pipeline ROW 

grant.

Will issue the decision to you in writing, and state the 

reasons for the denial. 

§ 250.1128 When will MMS temporarily 

suspend or prohibit construction of an 

ROW pipeline? 

The Regional Supervisor may suspend 

or temporarily prohibit construction 

operations if the Regional Supervisor 

determines that a significant change in 

conditions occurred after the Regional 

Supervisor granted a pipeline ROW, but 

before you complete construction of the 

associated ROW pipeline. 

§ 250.1129 What must I do if the as-built 

location of the associated ROW pipeline 

deviates from the approved pipeline ROW 

grant? 

The Regional Supervisor will notify 

you in writing if the Regional 

Supervisor determines that the as-built 

location of the associated ROW pipeline 

deviates from the approved pipeline 

ROW grant. Within 60 calendar days 

after the date you submitted the 

pipeline construction report to the 

Regional Supervisor (see § 250.1050(a)), 

you must: 

(a) Notify the lessee or designated 

lease operator of each lease, and the 

pipeline ROW holder of each pipeline 

ROW, that is crossed or could be 

affected by the associated pipeline as 

constructed; 

(b) Provide the Regional Supervisor 

with evidence of such notification; and 

(c) Submit an application under 

§ 250.1132(a)(3) to the Regional 

Supervisor for approval to modify the 

pipeline ROW grant. 

§ 250.1130 What rental fees and payment 

schedules apply to a pipeline ROW grant? 

(a) Rental fees. For the first calendar 

year, or fraction thereof, that you hold 

a pipeline ROW grant, and for each 

calendar year thereafter that the grant 

remains in effect, you must pay MMS an 

annual rental as follows: 

(1) You must pay $70.00 for each 

statute mile, or part of a statute mile, of 

the OCS that your pipeline ROW 

crosses; and 

(2) If you hold a pipeline ROW grant 

that includes a site for an accessory to 

your pipeline, you must pay MMS an 

additional annual rental according to 

the following table: 

If your accessory site is or will be located in water depths . . . You must pay MMS an additional annual rental of . . . 

(i) Less than 656 feet ............................................................................... $5.00 per acre, with a minimum of $450 for use of the affected area. 

(ii) 656 feet or greater .............................................................................. $7.50 per acre, with a minimum of $675 for use of the affected area. 

(b) Affected area. For purposes of this 

section, the affected area includes the 

areal extent of anchor chains, risers, 

appurtenances, and other devices 

associated with the accessory. 

(c) Payment schedule and deadline. 

You may make the rental payments 

required by paragraph (a) of this section 

to MMS on an annual basis, for a 5-year 

period, or for multiples of 5 years. All 

payment periods begin on January 1. 

You must pay all rental fees in advance 

and before the beginning of the payment 

period. 

(d) Late rental payments. You will be 

subject to an interest charge if you do 

not make a rental payment by the 

deadline specified in paragraph (c) of 

this section. 

(1) MMS will assess interest on a late 

payment on unpaid and underpaid 

amounts from the date the amounts are 

due. 

(2) MMS will assess interest only on 

the amount not received. 

(3) MMS will assess interest only for 

the number of days the payment is late. 

(4) The interest charge on a late rental 

payment will be at the underpayment 

rate established by the Internal Revenue 

Service Code, 26 U.S.C. 6621(a)(2) 

(Supp. 1987). 

(5) MMS may offset an overpayment 

you made on the rental for a pipeline 

ROW grant that you hold against an 

underpayment you made on a different 

pipeline ROW grant that you hold to 

determine the net underpayment for 

which interest is due. 

§ 250.1131 What are the terms and 

conditions for holding a pipeline ROW 

grant? 

(a) Compliance. You must comply 

with the OCSLA (43 U.S.C. 1331, et 

seq.), as amended, other applicable 

laws, and MMS regulations. 

(b) Address changes. You must 

update your qualification file (see 

§ 250.1117(b)) within 30 calendar days 

after a change of address as follows: 


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If you are . . . You must provide . . . 

(1) An individual .................................................. Your change of address. 

(2) A corporation or association ......................... Address of your principal place of business, or name and address of the officer or agent authorized to act on your behalf and to be served with process. 

(c) Non-interference. Your pipeline 

ROW grant does not allow you to 

prevent or interfere in any way with the 

management, administration, or the 

granting of other rights by the United 

States, either before or after the pipeline 

ROW is granted by MMS. 

(d) Occupancy and use. You must 

allow the occupancy and use by the 

United States, its lessees or designated 

lease operators, or other pipeline ROW 

holders of any part of the pipeline ROW 

grant not actually occupied, or 

necessarily incident to its use, for any 

necessary operations involved in the 

management, administration, or the 

enjoyment of other granted rights. 

(e) Compensation and 

indemnification. You must: 

(1) Compensate the United States, its 

lessees, or other pipeline ROW holders, 

as the case may be, for the full value of 

all damages to the property of the 

United States or of its lessees or 

pipeline ROW holders; and 

(2) Indemnify the United States 

against any and all liability for damages 

to life, person, or property arising from 

the occupation and use of the area 

covered by the pipeline ROW grant. 

(f) Federal Energy Regulatory 

Commission (FERC) determination. The 

pipeline associated with the pipeline 

ROW grant must transport, or you must 

purchase, oil or natural gas produced 

from submerged lands of the OCS in the 

vicinity of the pipeline in such 

proportionate amounts as FERC may 

determine to be reasonable. The FERC 

will make this determination only after 

a full hearing with due notice thereof to 

the interested parties, taking into 

account, among other things, 

conservation and the prevention of 

waste. 

(g) Open and nondiscriminatory 

access. (1) Unless otherwise exempted 

by FERC under section 5(f)(2) of the 

OCSLA (43 U.S.C. 1334(f)(2)), you must 

provide open and nondiscriminatory 

access to the associated ROW pipeline 

to both owner and non-owner shippers. 

(2) The express condition that ROW 

oil and natural gas pipelines must 

transport or purchase without 

discrimination is within MMS’s 

delegated authority to enforce, even 

when those pipelines are also under 

FERC jurisdiction by separate authority. 

To the extent that the oil or natural gas 

pipelines are subject to FERC’s 

jurisdiction, MMS intends to defer to 

FERC its authority to decide whether 

those pipelines have complied with the 

open and nondiscriminatory access 

requirements. For pipelines not under 

FERC jurisdiction, MMS will decide 

whether those pipelines have complied 

with the open and nondiscriminatory 

access requirements of the OCSLA. All 

complaints by shippers alleging that 

pipelines have not complied with the 

open and nondiscriminatory access 

requirements are subject to the 

regulations in 30 CFR part 291. 

(h) Expansion of throughput capacity. 

You must comply with the provisions of 

section 5(f)(1)(B) of the OCSLA (43 

U.S.C. 1334(f)(1)(B)), under which FERC 

may order expansion of the throughput 

capacity of an associated ROW pipeline 

that was approved after September 18, 

1978, and that is not located in the Gulf 

of Mexico or the Santa Barbara Channel. 

(i) Open for inspection. You must 

keep the area covered by the pipeline 

ROW grant, and all improvements 

thereon, open for inspection by MMS. 

(j) Nondiscrimination in employment. 

You must comply fully with Executive 

Order 11246, section 202, paragraphs (1) 

through (7), as amended (reprinted in 41 

CFR 60–1.4(a)), and must not 

discriminate against any employee or 

applicant for employment on the basis 

of race, color, religion, sex, or national 

origin. 

(k) Sabotage or subversive activity. 

You must immediately notify the 

Regional Supervisor, by the fastest 

possible means of communication, if 

you discover any evidence of sabotage 

or subversive activity involving or 

endangering any pipeline, accessory, 

vessel, aircraft, or any operation 

conducted under the pipeline ROW 

grant. 

§ 250.1132 How do I modify a pipeline 

ROW grant? 

(a) Application. You must submit one 

executed original and two copies of an 

application to modify a pipeline ROW 

grant to the Regional Supervisor for 

approval if you plan to: 

(1) Cease pipeline operations, and 

need to maintain the pipeline ROW 

grant in effect; 

(2) Change the purpose(s) for which 

the grant was made; 

(3) Change the route of the associated 

ROW pipeline; or 

(4) Establish a site for an accessory, or 

change the footprint of an accessory. 

(b) Associated pipeline application. 

For those applications specified in 

paragraphs (a)(2), (a)(3), and (a)(4) of 

this section, you must attach the 

application to modify the pipeline ROW 

grant to the application to modify the 

associated ROW pipeline (see 

§ 250.1093(a)). 

(c) Application contents. Your 

application to modify a pipeline ROW 

grant must include: 

(1) Company name; 

(2) Contact name, telephone number, 

telefax number, and e-mail address; 

(3) Reason for the modification, and a 

description of the proposed 

modification to the pipeline ROW grant; 

(4) MMS-assigned pipeline ROW 

number, the segment number of the 

associated pipeline, and, if applicable, 

the name of any accessory; 

(5) Name, title, and signature of your 

authorizing official. This information 

must be the same as the information you 

provided or referenced in the MMS 

qualification records; 

(6) If you propose to cease pipeline 

operations: 

(i) Date that you stopped using the 

pipeline; 

(ii) Steps you will take to resume 

operations under the pipeline ROW 

grant; 

(iii) The approximate date you intend 

to resume operations; and 

(iv) Plans for maintaining the 

associated ROW pipeline in the interim; 

(7) If the modification results in 

additional rental (see § 250.1130), 

payment for the increase in the manner 

prescribed in § 250.1126(h); and 

(d) MMS actions. The Regional 

Supervisor will review your application 

to modify a pipeline ROW grant, along 

with your application to modify the 

associated ROW pipeline (see 

§ 250.1093(a)), to ensure that it complies 

with the OCSLA (43 U.S.C. 1331, et 

seq.), other applicable laws, and 

applicable MMS regulations, and will 

take one of the actions prescribed in 

§ 250.1127(c). 

§ 250.1133 How does temporary cessation 

and cessation of pipeline operations affect 

a pipeline ROW grant? 

(a) Definitions—(1) Temporary 

cessation of pipeline operations means 

the use of a pipeline associated with a 

pipeline ROW grant for a purpose other 

than that for which the grant was made 

for a period of 180 consecutive calendar 

days or less. 


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(2) Cessation of pipeline operations 

means the use of a pipeline associated 

with a pipeline ROW grant for a purpose 

other than that for which the grant was 

made for a period of more than 180 

consecutive calendar days. Simply 

maintaining pressure on the pipeline is 

not using the pipeline for the purpose 

for which the grant was made. 

(b) Temporary cessation of pipeline 

operations. Temporary cessation of 

pipeline operations will not cause the 

associated pipeline ROW grant to 

expire. 

(c) Cessation of pipeline operations. 

Cessation of pipeline operations, 

whether voluntary or resulting from a 

suspension or temporary prohibition of 

operations directed by MMS, will cause 

the associated pipeline ROW grant to 

expire unless the Regional Supervisor 

approves an application to modify the 

pipeline ROW grant (see 

§ 250.1132(a)(1)) to allow for a cessation 

of operations for a specified time period. 

(d) Obligations. If MMS approves your 

application to modify the pipeline ROW 

grant to cease operations, you must: 

(1) Continue to pay the annual rentals 

required by § 250.1130(a); 

(2) Adhere to the requirements for 

out-of-service pipelines in § 250.1086; 

and 

(3) If, at any time, you determine that 

cessation of pipeline operations will 

continue for 5 years or more, or for a 

shorter period as specified by the 

Regional Supervisor, you must submit 

to the Regional Supervisor, within 60 

days: 

(i) A request to relinquish the pipeline 

ROW grant (see § 250.1136(a)); and 

(ii) An application to decommission 

the associated pipeline (see §§ 250.1107 

or 1108). 

§ 250.1134 How do I assign a pipeline 

ROW grant? 

(a) Assignment request. You may 

assign a pipeline ROW grant by 

submitting two originals of Form MMS–

149 (Assignment of Federal OCS 

Pipeline Right-of-Way Grant) to the 

Regional Supervisor for approval. The 

assignment must transfer the pipeline 

ROW grant in its entirety and to only 

one assignee. Your assignment request 

must include: 

(1) The MMS-assigned pipeline ROW 

number, the segment number of the 

associated pipeline, and, if applicable, 

the name of any accessory; 

(2) The names and MMS company 

numbers for both the assignor and the 

assignee; 

(3) The names and telephone numbers 

of the contacts for both the assignor and 

the assignee; 

(4) The names, titles, and signatures 

of the authorizing officials for both the 

assignor and the assignee; 

(5) Payment of a nonrefundable 

service fee (see § 250.125 for the 

amount); 

(6) A statement from the assignee that 

the assignee agrees to comply with, and 

to be bound by, the terms and 

conditions of the pipeline ROW grant; 

(7) The same showing of 

qualifications of the assignee as is 

required of an applicant for a pipeline 

ROW grant in § 250.1117; 

(8) A statement describing how the 

assignee will comply with the financial 

security requirements of § 250.1118; 

(9) The name of the identified 

operator, if the company that will 

operate the associated pipeline will not 

be the assignee; 

(10) A revised safety flow schematic 

that shows the new transfer point, if the 

assignment will result in a change of the 

jurisdictional transfer point of the 

associated pipeline; and 

(11) The information required by 

§§ 250.1028 and 250.1029. 

(b) Rental payments for a pipeline 

ROW grant pending assignment. If you 

have submitted a request to assign a 

pipeline ROW grant, you (the assignor) 

will be billed for the annual pipeline 

ROW rental payment if the payment is 

due (see § 250.1130(c)) and the Regional 

Supervisor has not yet approved the 

assignment. MMS will not mediate any 

financial disputes between an assignor 

and an assignee. 

(c) Effective date. The assignment 

takes effect on the date the Regional 

Supervisor approves it. 

(d) Assignor obligations. The assignor 

is liable for all obligations that accrue 

under a pipeline ROW grant before the 

date the Regional Supervisor approves 

the assignment. An assignment approval 

by MMS does not relieve the assignor of 

liability for accrued obligations that the 

assignee, or a subsequent assignee, fails 

to fulfill. 

(e) Assignee obligations. The assignee 

and each subsequent assignee: 

(1) Agrees to be bound by the terms 

and conditions of the pipeline ROW 

grant; and 

(2) Is liable for all obligations that 

accrue under a pipeline ROW grant after 

the date the Regional Supervisor 

approves the assignment. 

(f) Disqualification. The Director may 

disqualify you from acquiring any 

pipeline ROW grants by assignment if 

your operating performance is 

unacceptable. The Director will give you 

adequate notice, and an opportunity to 

have your case reviewed, before 

disqualification. 

(g) Financial securities. After the 

Regional Supervisor approves an 

assignment of a pipeline ROW grant, 

you may request that the Regional 

Director approve a ‘‘Termination of the 

Period of Liability’’ for your pipeline 

ROW area bond or other security and 

any additional securities (see 

§ 250.1119) if you: 

(1) No longer hold any pipeline ROW 

grants in an MMS OCS Region; and 

(2) Do not plan to become a pipeline 

ROW grant holder in the near future in 

that MMS OCS Region. 

§ 250.1135 When may MMS suspend a 

pipeline ROW grant? 

The Regional Supervisor may suspend 

a pipeline ROW grant if: 

(a) The Regional Supervisor suspends 

or temporarily prohibits operation of the 

associated ROW pipeline under 

§ 250.1091; 

(b) You fail to provide any additional 

security required by the Regional 

Director (see § 250.1118(c)), replace or 

provide additional coverage for a devalued bond or other security (see 

§ 250.1121(a)), or replace a lapsed or 

forfeited bond or other security (see 

§§ 250.1121(b) and 1122) within the 

prescribed time period; or 

(c) The Regional Supervisor 

determines that you have failed to 

comply with a provision of the OCSLA 

(43 U.S.C.1331, et seq.) or any other 

applicable law, a provision of applicable 

regulations, or a stipulation, term, or 

condition of the pipeline ROW grant. 

§ 250.1136 How do I relinquish a pipeline 

ROW grant? 

(a) Relinquishment request. You may 

voluntarily surrender a pipeline ROW 

grant, or a portion of a pipeline ROW 

grant, by filing one original and two 

copies of a relinquishment request with 

the Regional Supervisor for approval. 

You must attach the relinquishment 

request to the application required by 

§§ 250.1107 or 250.1108 to 

decommission the associated ROW 

pipeline and, if applicable, the 

application required by § 250.1727 to 

decommission an associated accessory. 

Your relinquishment request must 

include: 

(1) Company name; 

(2) Contact name, telephone number, 

telefax number, and e-mail address; 

(3) Reason you are requesting 

relinquishment of the pipeline ROW 

grant; 

(4) MMS-assigned pipeline ROW 

number, the segment number of the 

associated pipeline, and, if applicable, 

the name of any accessory; 

(5) Name, title, and signature of your 

authorizing official which must be the 


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same as the information you provide or 

reference in your MMS qualification 

records; 

(6) Payment of a nonrefundable 

service fee (see § 250.125 for the 

amount); and 

(7) A statement that you will adhere 

to the requirements of § 250.1138(a) and 

(b). 

(b) Rental payment for a pipeline 

ROW grant pending relinquishment. If 

you have submitted a request to 

relinquish a pipeline ROW grant, you 

will be billed for the annual pipeline 

ROW rental payment if the payment is 

due (see § 250.1130(c)) and the Regional 

Supervisor has not yet approved the 

relinquishment. 

(c) Delinquent payments. The 

Regional Supervisor will not approve 

your relinquishment request until you 

have paid all outstanding rentals and 

fines. 

(d) Effective date. The relinquishment 

takes effect on the date the Regional 

Supervisor approves it. 

(e) Financial securities. After the 

Regional Supervisor approves the 

relinquishment of a pipeline ROW grant 

you may request that the Regional 

Director approve a ‘‘Termination of the 

Period of Liability’’ for your pipeline 

ROW area bond or other security and 

any additional securities (see 

§ 250.1119) if you: 

(1) No longer hold any pipeline ROW 

grants in an MMS OCS Region; and 

(2) Do not plan to become a pipeline 

ROW grant holder in the near future in 

that MMS OCS Region. 

§ 250.1137 When will a pipeline ROW grant 

be cancelled, be forfeited, or expire? 

Your ROW grant will be cancelled, be 

forfeited, or expire as shown in the 

following table. 

Termination type When termination will occur 

(a) Cancellation .................... The Secretary may cancel a pipeline ROW grant if: 

(1) The Secretary cancels MMS approval of the application for the associated ROW pipeline pursuant to 

§ 250.1013; 

(2) You no longer qualify to hold a pipeline ROW grant; 

(3) You are disqualified from holding pipeline ROW grants according to § 250.1117(c); or 

(4) You fail to provide any additional security required by the Regional Director (see § 250.1118(c)), replace or 

provide additional coverage for a de-valued bond or other security (see § 250.1121(a)), or replace a lapsed or forfeited bond or other security (see §§ 250.1121(b) and 1122) within the prescribed time period. 

(b) Forfeiture ........................ You may forfeit a pipeline ROW grant, in an appropriate judicial proceeding instituted by the United States, in accordance with the provisions of § 23 of the OCSLA (43 U.S.C. 1349) if: 

(1) You fail to comply with the provisions of § 5(e) of the OCSLA (43 U.S.C. 1334(e)), or the regulations prescribed in this subpart; 

(2) The Director determines that you have not provided open access or nondiscriminatory access to a shipper; 

or 

(3) There is substantial deviation of an associated ROW pipeline (as constructed) from the pipeline ROW grant, 

and the Regional Supervisor has not approved a modification to the pipeline ROW grant. 

(c) Expiration ........................ A pipeline ROW grant expires if: 

(1) You do not construct the associated pipeline within 5 years after the grant was approved by the Regional 

Supervisor; 

(2) You ceased pipeline operations and did not obtain approval from the Regional Supervisor pursuant to 

§ 250.1132(a)(1); 

(3) You permanently discontinue using the associated ROW pipeline for any reason; or 

(4) You cease operations for 5 years. 

§ 250.1138 What must I do after a pipeline 

ROW grant terminates? 

(a) Pipeline operation. After a 

pipeline ROW grant terminates, for any 

reason (relinquishment, cancellation, 

forfeiture, or expiration), you must no 

longer use the associated pipeline. 

(b) Decommissioning. Within 1 year 

after a pipeline ROW grant terminates, 

you must decommission: 

(1) The associated ROW pipeline in 

accordance with the requirements of 

§§ 250.1106 through 1109 and 

§ 250.1111; and 

(2) Any associated accessory in 

accordance with the requirements of 

§§ 250.1725 through 1730 and 

§§ 250.1741 through 1743. 

(c) Failure to comply. If you fail to 

decommission the associated pipeline 

and any accessory within the prescribed 

time period: 

(1) You remain liable for 

decommissioning costs, and responsible 

for accidents or damages that might 

result from such failure; and 

(2) The violation may be subject to a 

civil penalty under 30 CFR 250, subpart 

N, Outer Continental Shelf (OCS) Civil 

Penalties. 

(d) Obligations. You remain liable for 

all obligations that accrued under a 

pipeline ROW grant before the date the 

pipeline ROW grant terminated. 

Accessories to Right-of-Way (ROW) 

Pipelines 

§ 250.1140 What are the requirements for 

an accessory to an ROW pipeline? 

(a) General. You must design, 

fabricate, install, and maintain an 

accessory to an ROW pipeline in 

accordance with the requirements of 30 

CFR 250, subpart I, Platforms and 

Structures. 

(b) Surface safety system. You must 

protect personnel, the environment, and 

the accessory with a basic and ancillary 

surface safety system. You must design, 

analyze, install, test, operate, and 

maintain the surface safety system in 

accordance with the applicable 

requirements of subpart H of this part, 

Oil and Gas Production Safety Systems. 

(c) Existing OCS platforms. If you 

plan to convert an existing OCS 

platform to an accessory, you must 

decommission all wells on the platform 

in accordance with the requirements of 

§§ 250.1715 and 250.1716 before the 

Regional Supervisor will approve the 

accessory application (see 

§ 250.1141(a)). 

§ 250.1141 How do I obtain approval to 

install, operate, and maintain an accessory? 

(a) Accessory application. Before you 

install, operate, and maintain an 

accessory to a ROW pipeline, you must 

submit three copies of an application to 

the Regional Supervisor for approval. 

You must attach the accessory 

application to the application for the 

associated ROW pipeline. Your 

accessory application must include all 

of the following: 

(1) The following information, based 

on the type of platform: 


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For . . . Your application must include . . . and . . . 

(i) New platforms ............................. the information required by 

§§ 250.905 and 912, if applicable.

(ii) Existing platforms that are being 

converted for a different use.

the information required by 

§ 250.905.

the results of your platform assessment in accordance with API RP 

2A–WSD, section 15, Reuse (incorporated by reference as specified in § 250.198). 

(iii) Existing platforms that are completing ongoing activity.the information required by 

§ 250.905.

the results of your platform assessment in accordance with API RP 

2A–WSD, section 17, Assessment of Existing Platforms (incorporated by reference as specified in § 250.198. 

(2) The MMS-assigned pipeline ROW 

number and the segment number of the 

associated pipeline, if the accessory will 

be under an existing pipeline ROW 

grant. 

(3) The maximum anchor radius (feet) 

of the construction vessel you will use 

to install the accessory. 

(4) Information on air emission 

sources that includes: 

(i) The rated output (horsepower) of 

each tug, construction vessel, and 

service vessel or equipment; 

(ii) An estimate of the number of 

vessel or equipment trips per year; 

(iii) An estimate of the time (days) 

that each vessel/equipment will be 

within 25 miles of the accessory; 

(iv) An estimate of the number of 

component connections (e.g., valves, 

flanges) on the accessory; 

(v) The contents and capacity 

(gallons) of hydrocarbon storage tanks, 

and their average daily and annual 

throughput (gallons/day and gallons/ 

year); and 

(vi) Documentation of any emission 

control technologies you will employ. 

(5) Information on combustion 

emission sources that includes: 

(i) The rated output (horsepower) of 

each emission source (e.g., crane, 

compressor, generator, dehydrator); 

(ii) The run time (hours/day and days/ 

year) for each emission source; and 

(iii) The average hourly and annual 

throughput of gas through glycol 

dehydrators. 

(6) Information on wastes generated at 

the accessory that includes, as 

appropriate: 

(i) The type and general characteristic 

of the wastes that will be generated by 

operations at the accessory and released 

(locally) into the ocean; 

(ii) The amount of waste to be 

discharged (gallons); 

(iii) The average maximum discharge 

rates (gallons/day); 

(iv) A description of any waste 

treatment or storage; and 

(v) The discharge location and 

method for each type of discharge. 

(7) The safety system design and 

installation information required by 

§ 250.802(e). 

(b) Electronic submission. You may 

submit part or all of your accessory 

application electronically (see 

§ 250.186(a)(3)). If you prefer to submit 

your application electronically, you 

should consult with the Regional 

Supervisor for further guidance. 

(c) Withdrawal of application. You 

may withdraw your accessory 

application, at any time, and for any 

reason, by notifying the Regional 

Supervisor in writing. 

§ 250.1142 How does MMS process an 

accessory application? 

(a) Completeness review. The Regional 

Supervisor will determine whether your 

accessory application is complete, and 

will notify you in writing of any 

problem or deficiency. The Regional 

Supervisor will not begin processing 

your application until it is complete. 

(b) Compliance review. The Regional 

Supervisor will review the proposed 

operations described in your accessory 

application to ensure that they conform 

to the OCSLA (43 U.S.C. 1331, et seq.), 

other applicable laws, and MMS 

regulations. 

(c) Environmental impact evaluation. 

The Regional Supervisor will evaluate 

the environmental impacts of the 

operations described in your accessory 

application, and prepare environmental 

documentation under NEPA (42 U.S.C. 

4321, et seq.) and the implementing 

regulations (40 CFR parts 1500 through 

1508). 

(d) Amendments. During the review 

of your accessory application, the 

Regional Supervisor may require you, or 

you may elect, to change the 

application. 

(e) MMS decision. The Regional 

Supervisor will review your accessory 

application and will notify you in 

writing of the decision. The Regional 

Supervisor will either: 

(1) Approve the application if it 

complies with all applicable 

requirements, and inform you of any 

conditions you may be required to meet; 

or 

(2) Disapprove the application, and 

inform you of the reasons for 

disapproval if the: 

(i) Proposed accessory operations 

would probably cause serious harm or 

damage to life (including fish or other 

aquatic life); property; mineral resources 

(in areas leased or not leased); the 

national security or defense; or the 

marine, coastal, or human environment; 

and you cannot amend the proposed 

accessory operations to avoid such 

condition(s); or 

(ii) Regional Supervisor has 

disapproved your application for a 

connecting ROW pipeline (see 

§ 250.1012(b)) or denied your 

application for the associated pipeline 

ROW grant (see § 250.1127(c)(3)). 

§ 250.1143 Who do I need to notify before 

I install an accessory? 

(a) Military installations. Before you 

install an accessory in an established 

military warning area or water test area, 

you must notify the commander of the 

military installation that exercises 

jurisdiction of the area concerning the 

control of electromagnetic emissions 

and the use of vessels, equipment, and 

aircraft in the area. 

(b) U.S. Coast Guard (USCG). You are 

encouraged to notify the applicable 

USCG Marine Safety Office at least 30 

calendar days before you conduct 

accessory installation operations so that 

a Notice to Mariners can be prepared. 

(c) National Geospatial-Intelligence 

Agency (NGA). You must notify the 

NGA in Bethesda, Maryland before you 

begin accessory installation operations. 

§ 250.1144 What information must I submit 

after an accessory is installed? 

You must submit three copies of an 

accessory installation report to the 

Regional Supervisor within 45 calendar 

days after you complete accessory 

installation. The installation report must 

include: 

(a) The MMS-assigned pipeline ROW 

number and the segment number of the 

associated pipeline; 

(b) The dates you started and 

concluded accessory installation 

operations; and 

(c) An ‘‘as built’’ location plat that 

depicts the accessory, based on the NAD 

27 for the GOMR (Gulf) and POCSR, or 

on the NAD 83 for the AKOCSR and 


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GOMR (Atlantic), drawn at a minimum 

scale of 1 inch = 2,000 feet. 

§ 250.1145 What accessory inspections 

must I conduct? 

You must conduct structural and 

pollution inspections on your accessory 

as required by this section. 

(a) Structural inspections. If the 

accessory is a platform, you must do all 

of the following: 

(1) Periodically inspect the platform 

in accordance with a comprehensive inservice inspection plan as required by 

§ 250.919(a). 

(2) As required by § 250.919(b), 

submit a written report, by November 1 

of each year, of the inspections that you 

conducted during the preceding 12 

months. The report must include: 

(i) The MMS-assigned pipeline ROW 

number and the segment number of the 

associated pipeline, and the MMS 

complex identification number for the 

platform; 

(ii) The extent and area of each 

inspection; 

(iii) The type of inspection conducted 

(i.e., visual, magnetic particle, 

ultrasonic); 

(iv) The results of the inspection; 

(v) A discussion of the overall 

condition of the platform; and 

(vi) A description of any necessary 

repairs. 

(b) Pollution inspections. If the 

accessory is a compressor or booster 

platform, you must inspect the 

accessory daily in accordance with 

§ 250.301 for evidence of pollution. You 

must retain the inspection records for at 

least two years, and make them 

available to MMS upon request. 

§ 250.1146 What must I do to modify an 

accessory? 

Before you conduct any operations to 

modify an approved accessory, you 

must submit three copies of a 

modification application to the Regional 

Supervisor for approval. In the 

accessory modification application, you 

must include: 

(a) The MMS-assigned pipeline ROW 

number and the segment number of the 

associated pipeline; 

(b) Those items in your approved 

application affected by the proposed 

modification; 

(c) If required by the Regional 

Supervisor, the step-by-step procedures 

you will follow to modify the accessory; 

and 

(d) If the accessory is a platform, the 

results of your platform assessment, 

based on platform assessment initiators 

listed in sections 17.2.1 through 17.2.5 

of API RP 2A–WSD (incorporated by 

reference as specified in § 250.198). 

§ 250.1147 When must I decommission an 

accessory? 

Within 1 year after an accessory has 

not been used for 5 years, or within 1 

year after you determine that an 

accessory will not be used for 5 years or 

more, you must decommission the 

accessory (see §§ 250.1725 through 1730 

and §§ 250.1740 through 1743). 

§ 250.1700 [AMENDED] 

8. In § 250.1700(a)(2), remove the 

phrase ‘‘or pipeline right-of-way.’’

§ 250.1701 [AMENDED] 

9. Amend § 250.1701 as follows: 

A. Remove paragraph (b); 

B. Redesignate paragraph (c) as 

paragraph (b); 

C. Remove the phrase ‘‘and to rightof-way holders as to facilities installed 

under the authority of a right-of-way’’ in 

newly redesignated paragraph (b); and 

D. Remove the comma after the word 

‘‘lease’’ and add in its place a period. 

10. In § 250.1702, revise paragraphs 

(b) and (d), remove paragraph (e), and 

redesignate paragraph (f) as paragraph 

(e). The revisions read as follows: 

§ 250.1702 When do I accrue 

decommissioning obligations? 

* * * * * 

(b) Install a platform or other facility; 

* * * * * 

(d) Are or become a lessee or the 

owner of operating rights of a lease on 

which there is a well that has not been 

permanently plugged according to this 

subpart, a platform, or other facility, or 

an obstruction; or 

* * * * * 

§ 250.1703 [Amended] 

11. In § 250.1703, remove paragraph 

(d) and redesignate paragraphs (e) and 

(f) as paragraphs (d) and (e). 

§ 250.1704 [Amended] 

12. In § 250.1704, remove paragraphs 

(d) and (e) and redesignate paragraphs 

(f) and (g) as paragraphs (d) and (e). 

§§ 250.1750 through 250.1754 [Removed] 

13. Remove §§ 250.1750 through 

250.1754 and the undesignated center 

heading ‘‘Pipeline Decommissioning’’

before § 250.1750. 

PART 253—OIL SPILL FINANCIAL 

RESPONSIBILITY FOR OFFSHORE 

FACILITIES 

14. The authority citation for part 253 

continues to read as follows: 

Authority: 33 U.S.C. 2701 et seq. 

15. In § 253.3, revise the definitions of 

the terms ‘‘Designated applicant,’’

‘‘Pipeline,’’ ‘‘Responsible party,’’ and 

‘‘Right of use and easement (RUE)’’ to 

read as follows: 

§ 253.3 How are the terms used in this 

regulation defined? 

* * * * * 

Designated applicant means the 

responsible party or, if there is more 

than one responsible party, a person 

that the responsible parties designate to 

demonstrate OSFR for a COF on a lease, 

permit, pipeline right-of-way (ROW), or 

right-of-use and easement (RUE). 

* * * * * 

Pipeline means the horizontal 

component, risers, and appurtenances 

installed for the purpose of transporting 

oil, gas, sulphur, and produced water. 

Responsible Party has the following 

meanings: 

(1) For a COF that is an ROW 

pipeline, responsible party means the 

pipeline ROW holder. 

(2) For a COF that is not an ROW 

pipeline, responsible party means either 

a lessee or permittee of the area on 

which the COF is located; or the holder 

of an RUE granted under applicable 

State law, or under the OCSLA (43 

U.S.C. 1331 et seq.) for the area in 

which the COF is located (if the holder 

is a different person than the lessee or 

permittee). A Federal agency, State, 

municipality, commission, or political 

subdivision of a State, or any interstate 

body that as owner transfers possession 

and right to use the property to another 

person by lease, assignment, or permit 

is not a responsible party. 

(3) For a decommissioned COF, 

responsible party means any person 

who would have been a responsible 

party for the COF immediately before 

decommissioning. 

Right-of-use and easement (RUE) 

means an authorization granted by MMS 

to use the OCS to construct and 

maintain platforms, artificial islands, 

and installations and other devices at an 

OCS site other than an OCS lease you 

own. This does not include pipeline 

ROWs. 

* * * * * 

16. Revise § 253.10 to read as follows: 

§ 253.10 What facilities does this part 

cover? 

(a) This part applies to any COF that 

is on any lease or permit issued, any 

ROW pipeline (see definition at 

§ 250.105 of this chapter), or on any 

RUE granted under the OCSLA (43 

U.S.C. 1331, et seq.) or applicable State 

law. 

(b) For a COF that is an ROW pipeline 

which extends onto land, this part 

applies to the portion of the pipeline 

lying seaward of the first accessible flow 

shut-off device on land. 


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17. Amend § 253.11 as follows: 

A. Redesignate paragraphs (d), (e), 

and (f) as paragraphs (e), (f), and (g), 

respectively. 

B. Add new paragraph (d), and revise 

newly redesignated paragraphs (e) and 

(f) as follows: 

§ 253.11 Who must demonstrate OSFR? 

* * * * * 

(d) The designated applicant for a 

ROW pipeline must be the pipeline 

ROW holder. 

(e) The designated applicant for a 

COF on a RUE must be the holder of the 

RUE. 

(f) MMS may require the designated 

applicant for a lease, permit, pipeline 

ROW, or RUE to be a person other than 

the person identified in paragraphs (b) 

through (e) of this section if MMS 

determines that the person identified in 

paragraphs (b) through (e) of this section 

cannot adequately demonstrate OSFR. 

* * * * * 

18. Revise § 253.15(a) as follows: 

§ 253.15 What are my general OSFR 

compliance responsibilities? 

(a) You must maintain continuous 

coverage for all your leases, permits, 

pipeline ROWs, and RUEs with COFs 

for which you are the designated 

applicant. 

* * * * * 

PART 254—OIL SPILL RESPONSE 

REQUIREMENTS FOR FACILITIES 

LOCATED SEAWARD OF THE 

COASTLINE 

19. The authority citation for part 254 

continues to read as follows: 

Authority: 33 U.S.C. 1321 

§ 254.6 [Amended] 

20. In § 254.6, revise the definition of 

‘‘Owner or operator’’ to read as follows: 

* * * * * 

Owner or operator means, in the case 

of an offshore facility, any person 

owning or operating such a facility. If 

the facility is a right-of-way (ROW) 

pipeline (see definition at § 250.105), 

the owner or operator is the pipeline 

ROW holder. In the case of a 

decommissioned offshore facility, it 

means the person who owned such 

facility immediately prior to such 

decommissioning. 

* * * * * 

PART 256—LEASING OF SULPHUR OR 

OIL AND GAS IN THE OUTER 

CONTINENTAL SHELF 

21. The authority citation for part 256 

continues to read as follows: 

Authority: 43 U.S.C. 1331, et seq., 42 

U.S.C. 6213, 31 U.S.C. 9701. 

22. In § 256.62, add a new paragraph 

(g) to read as follows: 

§ 256.62 Assignment of lease or interest in 

lease. 

* * * * * 

(g) Within 30 calendar days after 

MMS approves an assignment of a lease, 

or approves a new designation of 

operator for a lease under § 250.143 or 

§ 250.144, you (the new lessee or 

designated lease operator) must submit 

a report to the Regional Supervisor that: 

(1) Lists every lease term pipeline (see 

definition at § 250.105), including 

decommissioned pipelines on the lease; 

and 

(2) Indicates which pipelines 

remained as lease term pipelines after 

the lease assignment was approved by 

MMS. 

[FR Doc. 07–4831 Filed 10–2–07; 8:45 am] 

BILLING CODE 4310–MR–C 


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